NUREG-2192 

Standard Review Plan for 

Review of Subsequent 

License Renewal Applications 

for Nuclear Power Plants 

Final Report 

Office of Nuclear Reactor Regulation 

Standard Review Plan for 

Review of Subsequent 

License Renewal Applications 

for Nuclear Power Plants

Final Report 

Manuscript Completed: May 2017 

Date Published: July 2017 

Office of Nuclear Reactor Regulation 

NUREG–2192 

iii 

ABSTRACT 

This document provides guidance on the content of applications for renewal of the initial renewed 

operating license. The initial renewed operating license is the first renewed license issued under 

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

Operating Licenses for Nuclear Power Plants,” after either supersession or the expiration of the 

original operating license issued under either 10 CFR Part 50 or Part 52 following the completion 

of construction under a construction permit issued under Part 50, or a combined license issued 

under Part 52. In this guidance document, the renewal of the initial renewed operating license is 

referred to as “subsequent license renewal” (SLR). The Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) provides 

guidance to the U.S. Nuclear Regulatory Commission (NRC) staff reviewers in the Office of 

Nuclear Reactor Regulation. These reviewers perform safety reviews of applications to renew 

nuclear power plant licenses in accordance with 10 CFR Part 54. The NRC regulations in 

10 CFR 54.29 establish the standards for issuance of a renewed license. For nuclear power 

plants that have received a renewed license, the regulations in 10 CFR 54.31(d) state that “a 

renewed license may be subsequently renewed in accordance with all applicable requirements.” 

In the Statements of Consideration for the final rule, “Nuclear Power Plant License Renewal,” 

56 FR 64943, 64964-65 (December 13, 1991), the NRC stated that the requirements for 

subsequent renewal “include the provisions of [P]art 54 (unless the Commission subsequently 

adopts special provisions applicable only to subsequent renewals).” To date, the NRC has not 

adopted special provisions that apply only to subsequent renewal, so that the requirements in 

10 CFR Part 54 continue to govern SLR. 

The principal purposes of the SRP-SLR are to ensure the quality and uniformity of NRC staff 

reviews and to present a well-defined base from which to evaluate applicant programs and 

activities for the subsequent period of extended operation, following the first 20-year period of 

extended operation (i.e., the initial license renewal period). The SRP-SLR also is intended to 

make regulatory information widely available to enhance communication with interested members 

of the public and the nuclear power industry and to improve public and industry understanding of 

the NRC staff’s review process. The safety review is based primarily on the information provided 

by the applicant in a SLR application. Each of the individual SRP-SLR sections addresses: 

(i) who performs the review, (ii) the areas of review, (iii) the basis for review, (iv) the method of 

review, and (v) the conclusions from the review. 

This document is a companion document to NUREG–2191, “Generic Aging Lessons Learned for 

Subsequent License Renewal (GALL-SLR) Report,” that provides guidance for SLR applicants. 

The GALL-SLR Report contains the NRC staff’s generic evaluation of plant aging management 

programs and establishes the technical bases for their adequacy. The guidance in this document 

and the GALL-SLR Report are for the use of future applicants for SLR. The NRC does not intend 

to impose the guidance in this document and the GALL-SLR on current holders of an initial 

operating license renewal. However, this document and the GALL-SLR Report encompass all of 

the guidance applicable to initial license renewal. Accordingly, both current holders of initial 

operating licenses as well as future applicants for initial license renewal may voluntarily choose to 

reference an AMP in the GALL-SLR Report in their applications. However, such applicants 

should inform the NRC that they plan to demonstrate consistency with the GALL-SLR Report. 

Both the SRP-SLR and GALL-SLR Report were published for public comment in December 2015, 

with the comment period ending February 29, 2016. Numerous public comments were received 

by the staff. The public comments received were reviewed and dispositioned by the staff. The 

disposition of these comments and the technical bases for the staffs’ agreement or disagreement 
iv 

with these comments will be published shortly in a NUREG. The staff will also publish a second 

NUREG that will document all the technical changes made to the license renewal guidance 

documents published for first license renewal (i.e., for operation from 40 years to 60 years), along 

with the technical bases for these changes. 
v 

TABLE OF CONTENTS 

Section Page 

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

LIST OF TABLES ............................................................................................................................. xix

LIST OF CONTRIBUTORS .............................................................................................................. xxi

ABBREVIATIONS ...........................................................................................................................xxv

INTRODUCTION ............................................................................................................................ xxix

1 ADMINISTRATIVE INFORMATION ................................................................................ 1.1-1

1.1 Docketing of Timely and Sufficient Renewal Application .................................... 1.1-1

1.1.1 Areas of Review ....................................................................................... 1.1-1

1.1.1.1 Docketing and Sufficiency of Application ............................... 1.1-1

1.1.1.2 Timeliness of Application ....................................................... 1.1-1

1.1.2 Acceptance Criteria ................................................................................. 1.1-1

1.1.2.1 Docketing and Sufficiency of Application ............................... 1.1-1

1.1.2.2 Timeliness of Application ....................................................... 1.1-2

1.1.3 Review Procedures ................................................................................. 1.1-2

1.1.3.1 Docketing and Sufficiency of Application ............................... 1.1-2

1.1.3.2 Timeliness of Application ....................................................... 1.1-3

1.1.4 Evaluation Findings ................................................................................. 1.1-4

1.1.5 Implementation ........................................................................................ 1.1-4

1.1.6 References .............................................................................................. 1.1-4

1.2 Integrated Plant Assessments and Aging Management Reviews ...................... 1.2-1

1.2.1 Background on the Types of Reviews .................................................... 1.2-1

1.2.2 Applications With Approved Extended Power Uprates ........................... 1.2-6

1.2.3 Aging Management Programs That Rely on Implementation of 

Nuclear Regulatory Commission-Approved Technical or 

Topical Reports ........................................................................................ 1.2-6

2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING 

STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT 

REVIEW AND IMPLEMENTATION RESULTS ............................................................... 1.2-1

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

2.1.1 Areas of Review ....................................................................................... 2.1-1

2.1.1.1 Scoping .................................................................................. 2.1-1

2.1.1.2 Screening .............................................................................. 2.1-1

2.1.2 Acceptance Criteria ................................................................................. 2.1-2

2.1.2.1 Scoping .................................................................................. 2.1-2

2.1.2.2 Screening .............................................................................. 2.1-2

2.1.3 Review Procedures ................................................................................. 2.1-2

2.1.3.1 Scoping .................................................................................. 2.1-4

2.1.3.1.1 Safety-Related ....................................................... 2.1-5

2.1.3.1.2 Nonsafety-Related ................................................. 2.1-6

2.1.3.1.3 “Regulated Events” ................................................ 2.1-8

2.1.3.2 Screening .............................................................................. 2.1-9
vi 

2.1.3.2.1 “Passive” ................................................................ 2.1-9

2.1.3.2.2 “Long-Lived” ........................................................ 2.1-10

2.1.4 Evaluation Findings ............................................................................... 2.1-11

2.1.5 Implementation ...................................................................................... 2.1-11

2.1.6 References ............................................................................................ 2.1-11

2.2 Plant-Level Scoping Results ................................................................................ 2.2-1

2.2.1 Areas of Review ....................................................................................... 2.2-1

2.2.1.1 Systems and Structures Within the Scope of 

Subsequent License Renewal ............................................... 2.2-2

2.2.2 Acceptance Criteria ................................................................................. 2.2-2

2.2.2.1 Systems and Structures Within the Scope of 

Subsequent License Renewal ............................................... 2.2-2

2.2.3 Review Procedures ................................................................................. 2.2-3

2.2.3.1 Systems and Structures Within the Scope of 

Subsequent License Renewal ............................................... 2.2-3

2.2.4 Evaluation Findings ................................................................................. 2.2-4

2.2.5 Implementation ........................................................................................ 2.2-4

2.2.6 References .............................................................................................. 2.2-5

2.3 Scoping and Screening Results: Mechanical Systems ...................................... 2.3-1

2.3.1 Areas of Review ....................................................................................... 2.3-1

2.3.2 Acceptance Criteria ................................................................................. 2.3-2

2.3.2.1 Components Within the Scope of Subsequent License 

Renewal ................................................................................. 2.3-2

2.3.2.2 Components Subject to an Aging Management 

Review ................................................................................... 2.3-3

2.3.3 Review Procedures ................................................................................. 2.3-3

2.3.3.1 Components Within the Scope of Subsequent License 

Renewal ................................................................................. 2.3-3

2.3.3.2 Components Subject to an Aging Management 

Review ................................................................................... 2.3-4

2.3.4 Evaluation Findings ................................................................................. 2.3-5

2.3.5 Implementation ........................................................................................ 2.3-5

2.3.6 References .............................................................................................. 2.3-5

2.4 Scoping and Screening Results: Structures ....................................................... 2.4-1

2.4.1 Areas of Review ....................................................................................... 2.4-1

2.4.2 Acceptance Criteria ................................................................................. 2.4-2

2.4.2.1 Structural Components Subject to an Aging 

Management Review ............................................................. 2.4-2

2.4.3 Review Procedures ................................................................................. 2.4-3

2.4.3.1 Structural Components Within the Scope of 

Subsequent License Renewal ............................................... 2.4-3

2.4.3.2 Structural Components Subject to an Aging 

Management Review ............................................................. 2.4-3

2.4.4 Evaluation Findings ................................................................................. 2.4-5

2.4.5 Implementation ........................................................................................ 2.4-5

2.4.6 References .............................................................................................. 2.4-5

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Controls Systems ................................................................................................. 2.5-1

2.5.1 Areas of Review ....................................................................................... 2.5-1

2.5.2 Acceptance Criteria ................................................................................. 2.5-2
vii 

2.5.2.1 Components Within the Scope of Subsequent License 

Renewal ................................................................................. 2.5-2

2.5.2.1.1 Components Within the Scope of SBO (10 

CFR 50.63) ............................................................ 2.5-3

2.5.2.2 Components Subject to an Aging Management 

Review ................................................................................... 2.5-3

2.5.3 Review Procedures ................................................................................. 2.5-3

2.5.3.1 Components Within the Scope of Subsequent License 

Renewal ................................................................................. 2.5-4

2.5.3.2 Components Subject to an Aging Management 

Review ................................................................................... 2.5-5

2.5.4 Evaluation Findings ................................................................................. 2.5-6

2.5.5 Implementation ........................................................................................ 2.5-6

2.5.6 References .............................................................................................. 2.5-6

3 AGING MANAGEMENT REVIEW ................................................................................... 2.5-1

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

System ................................................................................................................. 3.1-1

3.1.1 Areas of Review ....................................................................................... 3.1-1

3.1.2 Acceptance Criteria ................................................................................. 3.1-2

3.1.2.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.1-2

3.1.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.1-2

3.1.2.2.1 Cumulative Fatigue Damage ................................ 3.1-2

3.1.2.2.2 Loss of Material Due to General, Pitting, 

and Crevice Corrosion .......................................... 3.1-3

3.1.2.2.3 Loss of Fracture Toughness Due to 

Neutron Irradiation Embrittlement ......................... 3.1-4

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking 

and Intergranular Stress 

Corrosion Cracking ................................................ 3.1-4

3.1.2.2.5 Crack Growth Due to Cyclic Loading .................... 3.1-5

3.1.2.2.6 Cracking Due to Stress Corrosion Cracking ......... 3.1-5

3.1.2.2.7 Cracking Due to Cyclic Loading ............................ 3.1-6

3.1.2.2.8 Loss of Material Due to Erosion ............................ 3.1-6

3.1.2.2.9 Aging Management of Pressurized Water 

Reactor Vessel Internals (Applicable to 

Subsequent License Renewal Periods 

Only) ...................................................................... 3.1-6

3.1.2.2.10 Loss of Material Due to Wear................................ 3.1-7

3.1.2.2.11 Cracking Due to Primary Water Stress 

Corrosion Cracking ................................................ 3.1-8

3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress 

Corrosion Cracking .............................................. 3.1-10

3.1.2.2.13 Loss of Fracture Toughness Due to 

Neutron Irradiation or Thermal 

Aging Embrittlement ............................................ 3.1-10
viii 

3.1.2.2.14 Loss of Preload Due to Thermal or 

Irradiation-Enhanced Stress Relaxation ............. 3.1-10

3.1.2.2.15 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................. 3.1-11

3.1.2.2.16 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys ........................................................ 3.1-12

3.1.2.2.17 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.1-13

3.1.2.2.18 Ongoing Review of Operating Experience ......... 3.1-13

3.1.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.1-13

3.1.2.4 Aging Management Programs ............................................. 3.1-13

3.1.2.5 Final Safety Analysis Report Supplement ........................... 3.1-14

3.1.3 Review Procedures ............................................................................... 3.1-14

3.1.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ..................................................... 3.1-14

3.1.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................. 3.1-14

3.1.3.2.1 Cumulative Fatigue Damage .............................. 3.1-14

3.1.3.2.2 Loss of Material Due to General, Pitting, 

and Crevice Corrosion ........................................ 3.1-15

3.1.3.2.3 Loss of Fracture Toughness Due to 

Neutron Irradiation Embrittlement ....................... 3.1-16

3.1.3.2.4 Cracking Due to Stress Corrosion Cracking 

and Intergranular Stress 

Corrosion Cracking .............................................. 3.1-16

3.1.3.2.5 Crack Growth Due to Cyclic Loading .................. 3.1-17

3.1.3.2.6 Cracking Due to Stress Corrosion Cracking ....... 3.1-17

3.1.3.2.7 Cracking Due to Cyclic Loading .......................... 3.1-18

3.1.3.2.8 Loss of Material Due to Erosion .......................... 3.1-18

3.1.3.2.9 Aging Management of PWR Reactor 

Vessel Internals (Applicable to Subsequent 

License Renewal Periods Only) .......................... 3.1-18

3.1.3.2.10 Loss of Material Due to Wear.............................. 3.1-19

3.1.3.2.11 Cracking Due to Primary Water Stress 

Corrosion Cracking .............................................. 3.1-20

3.1.3.2.12 Cracking Due to Irradiation-Assisted Stress 

Corrosion Cracking .............................................. 3.1-20

3.1.3.2.13 Loss of Fracture Toughness Due to 

Neutron Irradiation or Thermal Aging 

Embrittlement ...................................................... 3.1-21

3.1.3.2.14 Loss of Preload Due to Thermal or 

Irradiation-Enhanced Stress Relaxation ............. 3.1-21
ix 

3.1.3.2.15 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................. 3.1-22

3.1.3.2.16 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys ........................................................ 3.1-22

3.1.3.2.17 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.1-23

3.1.3.2.18 Ongoing Review of Operating Experience ......... 3.1-23

3.1.3.3 Aging Managing Review Results Not Consistent With 

or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.1-23

3.1.3.4 Aging Management Programs ............................................. 3.1-24

3.1.3.5 Final Safety Analysis Report Supplement ........................... 3.1-24

3.1.4 Evaluation Findings ............................................................................... 3.1-24

3.1.5 Implementation ...................................................................................... 3.1-25

3.1.6 References ............................................................................................ 3.1-25

3.2 Aging Management of Engineered Safety Features ........................................... 3.2-1

3.2.1 Areas of Review ....................................................................................... 3.2-1

3.2.2 Acceptance Criteria ................................................................................. 3.2-1

3.2.2.1 AMR Results Consistent With the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.2-2

3.2.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.2-2

3.2.2.2.1 Cumulative Fatigue Damage ................................ 3.2-2

3.2.2.2.2 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys .......................................................... 3.2-2

3.2.2.2.3 Loss of Material Due to General Corrosion 

and Flow Blockage Due to Fouling ....................... 3.2-4

3.2.2.2.4 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ........................................ 3.2-4

3.2.2.2.5 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.2-5

3.2.2.2.6 Ongoing Review of Operating Experience ........... 3.2-5

3.2.2.2.7 Loss of Material Due to Recurring Internal 

Corrosion ............................................................... 3.2-5

3.2.2.2.8 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys ................................................ 3.2-6

3.2.2.2.9 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................... 3.2-8

3.2.2.2.10 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................... 3.2-8

3.2.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report ................ 3.2-9

3.2.2.4 Aging Management Programs ............................................... 3.2-9
x 

3.2.2.5 Final Safety Analysis Report Supplement ........................... 3.2-10

3.2.3 Review Procedures ............................................................................... 3.2-10

3.2.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ..................................................... 3.2-10

3.2.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................. 3.2-11

3.2.3.2.1 Cumulative Fatigue Damage .............................. 3.2-11

3.2.3.2.2 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys ........................................................ 3.2-11

3.2.3.2.3 Loss of Material Due to General Corrosion 

and Flow Blockage Due to Fouling ..................... 3.2-12

3.2.3.2.4 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ...................................... 3.2-12

3.2.3.2.5 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.2-13

3.2.3.2.6 Ongoing Review of Operating Experience ......... 3.2-13

3.2.3.2.7 Loss of Material Due to Recurring Internal 

Corrosion ............................................................. 3.2-13

3.2.3.2.8 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys .............................................. 3.2-14

3.2.3.2.9 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................. 3.2-16

3.2.3.2.10 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................. 3.2-16

3.2.3.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.2-17

3.2.3.4 Aging Management Programs ............................................. 3.2-17

3.2.3.5 Final Safety Analysis Report Supplement ........................... 3.2-17

3.2.4 Evaluation Findings ............................................................................... 3.2-18

3.2.5 Implementation ...................................................................................... 3.2-18

3.2.6 References ............................................................................................ 3.2-18

3.3 Aging Management of Auxiliary Systems ............................................................ 3.3-1

3.3.1 Areas of Review ....................................................................................... 3.3-1

3.3.2 Acceptance Criteria ................................................................................. 3.3-2

3.3.2.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.3-2

3.3.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.3-2

3.3.2.2.1 Cumulative Fatigue Damage ................................ 3.3-3

3.3.2.2.2 Cracking Due to Stress Corrosion Cracking 

and Cyclic Loading ................................................ 3.3-3
xi 

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ........................................ 3.3-3

3.3.2.2.4 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys .......................................................... 3.3-4

3.3.2.2.5 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.3-5

3.3.2.2.6 Ongoing Review of Operating Experience ........... 3.3-5

3.3.2.2.7 Loss of Material Due to Recurring Internal 

Corrosion ............................................................... 3.3-5

3.3.2.2.8 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys ................................................ 3.3-6

3.3.2.2.9 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................... 3.3-8

3.3.2.2.10 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................... 3.3-9

3.3.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.3-10

3.3.2.4 Aging Management Programs ............................................. 3.3-10

3.3.2.5 Final Safety Analysis Report Supplement ........................... 3.3-10

3.3.3 Review Procedures ............................................................................... 3.3-11

3.3.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ..................................................... 3.3-11

3.3.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................. 3.3-11

3.3.3.2.1 Cumulative Fatigue Damage .............................. 3.3-11

3.3.3.2.2 Cracking Due to Stress Corrosion Cracking 

and Cyclic Loading .............................................. 3.3-11

3.3.3.2.3 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ...................................... 3.3-12

3.3.3.2.4 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys ........................................................ 3.3-13

3.3.3.2.5 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.3-13

3.3.3.2.6 Ongoing Review of Operating Experience ......... 3.3-14

3.3.3.2.7 Loss of Material Due to Recurring Internal 

Corrosion ............................................................. 3.3-14

3.3.3.2.8 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys .............................................. 3.3-14

3.3.3.2.9 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................. 3.3-16

3.3.3.2.10 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................. 3.3-16
xii 

3.3.3.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.3-17

3.3.3.4 Aging Management Programs ............................................. 3.3-18

3.3.3.5 Final Safety Analysis Report Supplement ........................... 3.3-18

3.3.4 Evaluation Findings ............................................................................... 3.3-18

3.3.5 Implementation ...................................................................................... 3.3-19

3.3.6 References ............................................................................................ 3.3-19

3.4 Aging Management of Steam and Power Conversion System .......................... 3.4-1

3.4.1 Areas of Review ....................................................................................... 3.4-1

3.4.2 Acceptance Criteria ................................................................................. 3.4-2

3.4.2.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.4-2

3.4.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.4-2

3.4.2.2.1 Cumulative Fatigue Damage ................................ 3.4-2

3.4.2.2.2 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ........................................ 3.4-3

3.4.2.2.3 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys .......................................................... 3.4-4

3.4.2.2.4 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.4-5

3.4.2.2.5 Ongoing Review of Operating Experience ........... 3.4-5

3.4.2.2.6 Loss of Material Due to Recurring Internal 

Corrosion ............................................................... 3.4-5

3.4.2.2.7 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys ................................................ 3.4-6

3.4.2.2.8 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................... 3.4-7

3.4.2.2.9 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................... 3.4-8

3.4.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report ................ 3.4-9

3.4.2.4 Aging Management Programs ............................................... 3.4-9

3.4.2.5 Final Safety Analysis Report Supplement ........................... 3.4-10

3.4.3 Review Procedures ............................................................................... 3.4-10

3.4.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ..................................................... 3.4-10

3.4.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................. 3.4-10

3.4.3.2.1 Cumulative Fatigue Damage .............................. 3.4-11
xiii 

3.4.3.2.2 Cracking Due to Stress Corrosion Cracking 

in Stainless Steel Alloys ...................................... 3.4-11

3.4.3.2.3 Loss of Material Due to Pitting and Crevice 

Corrosion in Stainless Steel and 

Nickel Alloys ........................................................ 3.4-12

3.4.3.2.4 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.4-12

3.4.3.2.5 Ongoing Review of Operating Experience ......... 3.4-13

3.4.3.2.6 Loss of Material Due to Recurring Internal 

Corrosion ............................................................. 3.4-13

3.4.3.2.7 Cracking Due to Stress Corrosion Cracking 

in Aluminum Alloys .............................................. 3.4-13

3.4.3.2.8 Loss of Material Due to General, Crevice or 

Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking .................................. 3.4-15

3.4.3.2.9 Loss of Material Due to Pitting and Crevice 

Corrosion in Aluminum Alloys ............................. 3.4-16

3.4.3.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.4-16

3.4.3.4 Aging Management Programs ............................................. 3.4-17

3.4.3.5 Final Safety Analysis Report Supplement ........................... 3.4-17

3.4.4 Evaluation Findings ............................................................................... 3.4-18

3.4.5 Implementation ...................................................................................... 3.4-18

3.4.6 References ............................................................................................ 3.4-18

3.5 Aging Management of Containments, Structures, and 

Component Supports ........................................................................................... 3.5-1

3.5.1 Areas of Review ....................................................................................... 3.5-1

3.5.2 Acceptance Criteria ................................................................................. 3.5-2

3.5.2.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.5-2

3.5.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.5-2

3.5.2.2.1 Pressurized Water Reactor and Boiling 

Water Reactor Containments ................................ 3.5-3

3.5.2.2.2 Safety-Related and Other Structures and 

Component Supports ............................................ 3.5-5

3.5.2.2.3 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.5-8

3.5.2.2.4 Ongoing Review of Operating Experience ........... 3.5-8

3.5.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report ................ 3.5-8

3.5.2.4 Aging Management Programs ............................................... 3.5-8

3.5.2.5 Final Safety Analysis Report Supplement ............................. 3.5-8

3.5.3 Review Procedures ................................................................................. 3.5-9
xiv 

3.5.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.5-9

3.5.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.5-9

3.5.3.2.1 Pressurized Water Reactor and Boiling 

Water Reactor Containments ................................ 3.5-9

3.5.3.2.2 Safety-Related and Other Structures, and 

Component Supports .......................................... 3.5-13

3.5.3.2.3 Quality Assurance for Aging Management 

of Nonsafety-Related Components ..................... 3.5-17

3.5.3.2.4 Ongoing Review of Operating Experience ......... 3.5-17

3.5.3.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report .............. 3.5-18

3.5.3.4 Aging Management Programs ............................................. 3.5-18

3.5.3.5 Final Safety Analysis Report Supplement ........................... 3.5-18

3.5.4 Evaluation Findings ............................................................................... 3.5-19

3.5.5 Implementation ...................................................................................... 3.5-19

3.5.6 References ............................................................................................ 3.5-19

3.6 Aging Management of Electrical and Instrumentation and Controls .................. 3.6-1

3.6.1 Areas of Review ....................................................................................... 3.6-1

3.6.2 Acceptance Criteria ................................................................................. 3.6-1

3.6.2.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.6-2

3.6.2.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.6-2

3.6.2.2.1 Electrical Equipment Subject to 

Environmental Qualification .................................. 3.6-2

3.6.2.2.2 Reduced Insulation Resistance Due to Age 

Degradation of Cable Bus Arrangements 

Caused by Intrusion of Moisture, Dust, 

Industrial Pollution, Rain, Ice, Photolysis, 

Ohmic Heating and Loss of Strength of 

Support Structures and Louvers of Cable 

Bus Arrangements Due to General 

Corrosion and Exposure to Air Outdoor ................ 3.6-2

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 

Preload for Transmission Conductors, 

Switchyard Bus, and Connections ........................ 3.6-3

3.6.2.2.4 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.6-3

3.6.2.2.5 Ongoing Review of Operating Experience ........... 3.6-3
xv 

3.6.2.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report ................ 3.6-3

3.6.2.4 Aging Management Programs ............................................... 3.6-3

3.6.2.5 Final Safety Analysis Report Supplement ............................. 3.6-4

3.6.3 Review Procedures ................................................................................. 3.6-4

3.6.3.1 Aging Management Review Results Consistent With 

the Generic Aging Lessons Learned for Subsequent 

License Renewal Report ....................................................... 3.6-4

3.6.3.2 Aging Management Review Results for Which Further 

Evaluation Is Recommended by the Generic Aging 

Lessons Learned for Subsequent License Renewal 

Report .................................................................................... 3.6-5

3.6.3.2.1 Electrical Equipment Subject to 

Environmental Qualification .................................. 3.6-5

3.6.3.2.2 Reduced Insulation Resistance Due to Age 

Degradation of Cable Bus Arrangements 

Caused by Intrusion of Moisture, Dust, 

Industrial Pollution, Rain, Ice, Photolysis, 

Ohmic Heating and Loss of Strength of 

Support Structures and Louvers of Cable 

Bus Arrangements Due to General 

Corrosion and Exposure to Air Outdoor ................ 3.6-5

3.6.3.2.3 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 

Preload for Transmission Conductors, 

Switchyard Bus, and Connections ........................ 3.6-5

3.6.3.2.4 Quality Assurance for Aging Management 

of Nonsafety-Related Components ....................... 3.6-5

3.6.3.2.5 Ongoing Review of Operating Experience ........... 3.6-6

3.6.3.3 Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons 

Learned for Subsequent License Renewal Report ................ 3.6-6

3.6.3.4 Aging Management Programs ............................................... 3.6-6

3.6.3.5 Final Safety Analysis Report Supplement ............................. 3.6-6

3.6.4 Evaluation Findings ................................................................................. 3.6-7

3.6.5 Implementation ........................................................................................ 3.6-7

3.6.6 References .............................................................................................. 3.6-7

4 TIME-LIMITED AGING ANALYSES ................................................................................ 3.6-1

4.1 Identification of Time-Limited Aging Analyses and Exemptions ......................... 4.1-1

4.1.1 Areas of Review ....................................................................................... 4.1-1

4.1.2 Acceptance Criteria ................................................................................. 4.1-1

4.1.3 Review Procedures ................................................................................. 4.1-3

4.1.4 Evaluation Findings ................................................................................. 4.1-5

4.1.5 References .............................................................................................. 4.1-5

4.2 Reactor Pressure Vessel Neutron Embrittlement Analyses ............................... 4.2-1

4.2.1 Areas of Review ....................................................................................... 4.2-1

4.2.2 Acceptance Criteria ................................................................................. 4.2-1
xvi 

4.2.2.1 Time-Limited Aging Analyses ................................................ 4.2-1

4.2.2.1.1 Neutron Fluence .................................................... 4.2-2

4.2.2.1.2 Upper-Shelf Energy ............................................... 4.2-3

4.2.2.1.3 Pressurized Thermal Shock (for PWRs) ............... 4.2-3

4.2.2.1.4 Pressure-Temperature Limits ............................... 4.2-4

4.2.2.1.5 Elimination of Boiling Water Reactor 

Circumferential Weld Inspections ......................... 4.2-5

4.2.2.1.6 Boiling Water Reactor Axial Welds ....................... 4.2-5

4.2.2.2 Final Safety Analysis Report Supplement ............................. 4.2-6

4.2.3 Review Procedures ................................................................................. 4.2-6

4.2.3.1 Time-Limited Aging Analyses ................................................ 4.2-6

4.2.3.1.1 Neutron Fluence .................................................... 4.2-6

4.2.3.1.2 Upper-Shelf Energy ............................................... 4.2-7

4.2.3.1.3 Pressurized Thermal Shock (for 

Pressurized Water Reactors) ................................ 4.2-8

4.2.3.1.4 Pressure-Temperature Limits ............................. 4.2-10

4.2.3.1.5 Elimination of Boiling Water Reactor 

Circumferential Weld Inspection ......................... 4.2-13

4.2.3.1.6 Boiling Water Reactor Axial Welds ..................... 4.2-13

4.2.3.2 Final Safety Analysis Report Supplement ........................... 4.2-13

4.2.4 Evaluation Findings ............................................................................... 4.2-13

4.2.5 References ............................................................................................ 4.2-14

4.3 Metal Fatigue ....................................................................................................... 4.3-1

4.3.1 Area of Review ........................................................................................ 4.3-1

4.3.2 Acceptance Criteria ................................................................................. 4.3-2

4.3.2.1 Time-Limited Aging Analysis ................................................. 4.3-2

4.3.2.1.1 Components Evaluated for Fatigue 

Parameters Other than CUFen .............................. 4.3-2

4.3.2.1.2 Components Evaluated for CUFen ........................ 4.3-3

4.3.2.2 Final Safety Analysis Report Supplement ............................. 4.3-4

4.3.3 Review Procedures ................................................................................. 4.3-5

4.3.3.1 Time-Limited Aging Analysis ................................................. 4.3-5

4.3.3.1.1 Components Evaluated for Fatigue 

Parameters Other Than CUFen ............................. 4.3-5

4.3.3.1.2 Components Evaluated for CUFen ........................ 4.3-6

4.3.3.2 Final Safety Analysis Report Supplement ............................. 4.3-8

4.3.4 Evaluation Findings ................................................................................. 4.3-8

4.3.5 References .............................................................................................. 4.3-9

4.4 Environmental Qualification (EQ) of Electric Equipment .................................... 4.4-1

4.4.1 Areas of Review ....................................................................................... 4.4-1

4.4.1.1 Time-Limited Aging Analysis ................................................. 4.4-2

4.4.1.1.1 Division of Operating Reactors Guidelines ........... 4.4-2

4.4.1.1.2 NUREG–0588, Category II (IEEE STD 323-

1971) ...................................................................... 4.4-2

4.4.1.1.3 NUREG–0588, Category I (IEEE STD 323-

1974) ...................................................................... 4.4-2

4.4.1.2 Generic Safety Issue ............................................................. 4.4-3

4.4.1.3 Final Safety Analysis Report Supplement ............................. 4.4-3

4.4.2 Acceptance Criteria ................................................................................. 4.4-3

4.4.2.1 Time-Limited Aging Analysis ................................................. 4.4-3

4.4.2.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.4-4
xvii 

4.4.2.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.4-4

4.4.2.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.4-4

4.4.2.2 Final Safety Analysis Report Supplement ............................. 4.4-4

4.4.3 Review Procedures ................................................................................. 4.4-4

4.4.3.1 Time-Limited Aging Analysis ................................................. 4.4-4

4.4.3.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.4-5

4.4.3.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.4-5

4.4.3.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.4-5

4.4.3.2 Final Safety Analysis Report Supplement ............................. 4.4-6

4.4.4 Evaluation Findings ................................................................................. 4.4-6

4.4.5 References .............................................................................................. 4.4-7

4.5 Concrete Containment Unbonded Tendon Prestress Analysis ............................ 4.5-1

4.5.1 Areas of Review ....................................................................................... 4.5-1

4.5.2 Acceptance Criteria ................................................................................. 4.5-1

4.5.2.1 Time-Limited Aging Analysis ................................................. 4.5-1

4.5.2.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.5-2

4.5.2.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.5-2

4.5.2.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.5-2

4.5.2.2 Final Safety Analysis Report Supplement ............................. 4.5-2

4.5.3 Review Procedures ................................................................................. 4.5-2

4.5.3.1 Time-Limited Aging Analysis ................................................. 4.5-3

4.5.3.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.5-3

4.5.3.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.5-3

4.5.3.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.5-3

4.5.3.2 Final Safety Analysis Report Supplement ............................. 4.5-4

4.5.4 Evaluation Findings ................................................................................. 4.5-4

4.5.5 References .............................................................................................. 4.5-4

4.6 Containment Liner Plate, Metal Containments, and Penetrations 

Fatigue Analysis ................................................................................................... 4.6-1

4.6.1 Areas of Review ....................................................................................... 4.6-1

4.6.1.1 Time-Limited Aging Analysis (Fatigue Parameter 

Evaluations) ........................................................................... 4.6-2

4.6.1.1.1 Fatigue Analyses (ASME Section III, MC or 

Class 1) .................................................................. 4.6-2

4.6.1.1.2 Fatigue Waiver Evaluations .................................. 4.6-3

4.6.1.2 Final Safety Analysis Report Supplement ............................. 4.6-3

4.6.2 Acceptance Criteria ................................................................................. 4.6-3

4.6.2.1 Time-Limited Aging Analysis ................................................. 4.6-3

4.6.2.1.1 Fatigue Parameter Evaluations ............................. 4.6-4

4.6.2.2 Final Safety Analysis Report Supplement ............................. 4.6-4

4.6.3 Review Procedures ................................................................................. 4.6-5

4.6.3.1 Time-Limited Aging Analysis ................................................. 4.6-5

4.6.3.1.1 Fatigue Parameter Evaluations ............................. 4.6-5

4.6.3.2 Final Safety Analysis Report Supplement ............................. 4.6-6

4.6.4 Evaluation Findings ................................................................................. 4.6-6

4.6.5 References .............................................................................................. 4.6-7

4.7 Other Plant-Specific Time-Limited Aging Analyses ............................................ 4.7-1

4.7.1 Areas of Review ....................................................................................... 4.7-1

4.7.1.1 Time-Limited Aging Analysis ................................................. 4.7-1

4.7.1.2 Final Safety Analysis Report Supplement ............................. 4.7-2

4.7.2 Acceptance Criteria ................................................................................. 4.7-2
xviii 

4.7.2.1 Time-Limited Aging Analysis ................................................. 4.7-2

4.7.2.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.7-2

4.7.2.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.7-2

4.7.2.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.7-2

4.7.2.2 Final Safety Analysis Report Supplement ............................. 4.7-2

4.7.3 Review Procedures ................................................................................. 4.7-3

4.7.3.1 Time-Limited Aging Analysis ................................................. 4.7-3

4.7.3.1.1 10 CFR 54.21(c)(1)(i) ............................................ 4.7-3

4.7.3.1.2 10 CFR 54.21(c)(1)(ii) ........................................... 4.7-3

4.7.3.1.3 10 CFR 54.21(c)(1)(iii) ........................................... 4.7-4

4.7.3.2 Final Safety Analysis Report Supplement ............................. 4.7-4

4.7.4 Evaluation Findings ................................................................................. 4.7-5

4.7.5 References .............................................................................................. 4.7-5

5 TECHNICAL SPECIFICATIONS CHANGES .................................................................. 4.7-1

5.1 Review of Technical Specifications Changes and Additions Necessary 

to Manage the Effects of Aging During the Subsequent Period of 

Extended Operation ............................................................................................. 5.1-1

5.1.1 Areas of Review ....................................................................................... 5.1-1

5.1.2 Acceptance Criteria ................................................................................. 5.1-1

5.1.3 Review Procedures ................................................................................. 5.1-2

5.1.4 Evaluation Findings ................................................................................. 5.1-3

5.1.5 References .............................................................................................. 5.1-3

APPENDIX A—GENERAL NRC STAFF POSITIONS AND GUIDANCE.................................. A.1-1
xix 

LIST OF TABLES 

Table 1.1-1 Acceptance Review Checklist for Subsequent License Renewal Application 

Acceptability for Docketing .................................................................................. 1.1-5

Table 2.1-1 Sample Listing of Potential Information Sources .............................................. 2.1-13

Table 2.1-2 Specific Staff Guidance on Scoping .................................................................. 2.1-14

Table 2.1-3 Specific Staff Guidance on Screening ............................................................... 2.1-16

Table 2.1-4 Typical “Passive” Structure-Intended Functions ............................................... 2.1-17

Table 2.1-5 Typical “Passive” Component-Intended Functions ........................................... 2.1-18

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment .......... 2.1-19

Table 2.2-1 Examples of System and Structure Scoping and Basis for Disposition ............. 2.2-6

Table 2.3-1 Examples of Mechanical Components Scoping and Basis for Disposition ........ 2.3-6

Table 2.3-2 Examples of Mechanical Components Screening and Basis for Disposition ..... 2.3-7

Table 2.3-3 Examples of Mechanical Component-Intended Functions ................................. 2.3-8

Table 2.4-1 Examples of Structural Components Scoping/Screening and Basis 

for Disposition ...................................................................................................... 2.4-6

Table 2.5-1 Examples of “Plant Spaces” Approach for Electrical and I&C Scoping and 

Corresponding Review Procedures ..................................................................... 2.5-7

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, 

and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR 

Report................................................................................................................. 3.1-29

Table 3.1-2 AMPs and Additional Guidance Appendices Recommended for Aging 

Management of Reactor Vessel, Internals, and Reactor Coolant System ....... 3.1-59

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features 

Evaluated in Chapter V of the GALL-SLR Report ............................................. 3.2-20

Table 3.2-2 AMPs and Additional Guidance Appendices Recommended for Aging 

Management of Engineered Safety Features ................................................... 3.2-48

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated 

in Chapter VII of the GALL-SLR Report ............................................................ 3.3-20

Table 3.3-2 AMPs and Additional Guidance Appendices Recommended for Aging 

Management of Auxiliary Systems .................................................................... 3.3-75

Table 3.4-1 Summary of Aging Management Programs for Steam and Power 

Conversion System Evaluated in Chapter VIII of the GALL-SLR Report ......... 3.4-20

Table 3.4-2 AMPs and Additional Guidance Appendices Recommended for Aging 

Management of Steam and Power Conversion System ................................... 3.4-47

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures 

and Component Supports Evaluated in Chapters II and III of the GALL-SLR 

Report................................................................................................................. 3.5-22

Table 3.5-2 AMPs and Additional Guidance Appendices Recommended for 

Containments, Structures, and Component Supports ...................................... 3.5-41

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components 

Evaluated in Chapter VI of the GALL-SLR Report ............................................. 3.6-8

Table 3.6-2 AMPs and Additional Guidance Appendices Recommended for Electrical 

and Instrumentation and Control Systems ........................................................ 3.6-17

Table 4.1-1 Sample Process for Identifying Potential Time-Limited Aging Analyses 

(TLAAs) and Basis for Disposition ....................................................................... 4.1-6

Table 4.1-2 Generic Time-Limited Aging Analyses .............................................................. 4.1-10

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses ..................................................................................... 4.2-16
xx 

Table 4.3-1 Examples of FSAR Supplement for Metal Fatigue TLAA Evaluation ............... 4.3-11

Table 4.4-1 Environmental Qualification Reanalysis and Ongoing Qualification 

Attributes .............................................................................................................. 4.4-9

Table 4.4-2 Examples of FSAR Supplement for Environmental Qualification Electric 

Equipment TLAA Evaluation .............................................................................. 4.4-11

Table 4.5-1 Examples of FSAR Supplement for Concrete Containment Tendon 

Prestress TLAA Evaluation .................................................................................. 4.5-6

Table 4.6-1 Examples of FSAR Supplement for Containment Liner Plates, Metal 

Containments, and Penetrations Fatigue TLAA Evaluation ............................... 4.6-8

Table 4.7-1 Examples of Potential Plant-Specific TLAA Topics ............................................. 4.7-6

Table A.1-1 Elements of an Aging Management Program for Subsequent 

License Renewal ............................................................................................... A.1-11 
xxi 

LIST OF CONTRIBUTORS1

Division of License Renewal, Office of Nuclear Reactor Regulation 

B. Holian Division Director 

C. Miller Division Director 

J. Lubinski Division Director 

G. Wilson Division Director 

R. Cadwell Deputy Division Director 

M. Delligatti Deputy Division Director 

J. Donoghue Deputy Division Director 

M. Galloway Deputy Division Director 

J. Marshall Deputy Director and Acting Division Director 

B. Beasley Acting Deputy Division Director 

S. Weerakkody Deputy Division Director 

S. Bloom Branch Chief 

Y. Diaz-Sanabria Branch Chief 

M. Marshall Branch Chief 

D. Morey Branch Chief 

B. Pham Branch Chief 

B. Wittick Branch Chief 

A. Hiser Senior Technical Advisor 

B. Brady Technical Project Manager Lead 

W. Burton Regulatory Project Manager Lead 

A. Billoch Lead Project Manager 

B. Litkett Lead Project Manager 

H. Jones Lead Project Manager 

J. Mitchell Lead Project Manager 

R. Plasse Lead Project Manager 

B. Rogers Lead Project Manager 

E. Sayoc Lead Project Manager 

A. Wong Lead Project Manager 

E. Gettys Public Coordination 

A. Kazi Public Coordination 

B. Allik Mechanical Engineering 

A. Bufford Structural Engineering 

D. Brittner Project Manager 

C. Doutt Electrical Engineering 

B. Fu Mechanical Engineering 

W. Gardner Mechanical Engineering 

 

1The titles in this List of Contributors refer to the NRC staff’s role in the development of this document, not their 

current position. 
xxii 

J. Gavula Mechanical Engineering 

B. Grange Project Manager 

K. Green Mechanical Engineering 

W. Holston Mechanical Engineering 

C. Hovanec Materials Engineering 

R. Kalikian Mechanical Engineering 

J. Medoff Mechanical Engineering 

S. Min Materials Engineering 

A. Prinaris Structural Engineering 

M. Sadollah Electrical Engineering 

G. Thomas Structural Engineering 

M. Yoo Mechanical Engineering 

Other Divisions in the Office of Nuclear Reactor Regulation

D. Alley Branch Chief 

S. Bailey Branch Chief 

R. Dennig Branch Chief 

C. Jackson Branch Chief 

A. Klein Branch Chief 

G. Kulesa Branch Chief 

T. Lupold Branch Chief 

J. McHale Branch Chief 

S. Rosenberg Branch Chief 

J. Zimmerman Branch Chief 

R. Hardies Senior Level Advisor 

K. Karwoski Senior Level Advisor 

L. Banic Project Manager 

G. Cheruvenki Materials Engineering 

J. Collins Materials Engineering 

S. Cumblidge Materials Engineering 

A. Erickson Structural Engineering 

C. Fairbanks Materials Engineering 

M. Hardgrove Mechanical Engineering 

K. Hoffman Materials Engineering 

A. Johnson Reactor Operations Engineering 

S. Jones Reactor Systems Engineering 

B. Lee Reactor Systems Engineering 

B. Lehman Structural Engineering 

R. Mathew Electrical Engineering 

N. Iqbal Fire Protection Engineer 

C. Ng Mechanical Engineering 

D. Nguyen Electrical Engineering 
xxiii 

A. Obodoako Materials Engineer 

A. Patel Reactor Engineering 

B. Parks Reactor Engineering 

J. Poehler Materials Engineering 

P. Purtscher Materials Engineering 

S. Ray Electrical Engineering 

S. Sheng Materials Engineering 

A. Tsirigotis Mechanical Engineer 

P. Verdi International Assignee 

O. Yee Reactor Systems Engineering 

M. Yoder Chemical Engineering 

Region II

P. Cooper Sr. Reactor Inspector

J. Rivera-Ortiz Reactor Inspector 

Region III

N. Feliz-Adorno Sr. Reactor Inspector 

M. Holmberg Sr. Reactor Inspector 

C. Tilton Sr. Reactor Inspector 

Region IV

S. Graves Sr. Reactor Inspector 

G. Pick Sr. Reactor Inspector 

M. Williams Reactor Inspector 

Office of New Reactors

J. Xu Branch Chief 

A. Istar Structural Engineering 

Office of Nuclear Material Safety and Safeguards

A. Csontos Branch Chief

J. Wise Materials Engineering

Office of Nuclear Regulatory Research

J. Burke Branch Chief 

S. Frankl Branch Chief 

M. Gavrilas Branch Chief 

J. Nakoski Branch Chief 

W. Ott Branch Chief 

D. Rudland Branch Chief 

M. Salley Branch Chief 

R. Sydnor Branch Chief 

J. Ake Senior Technical Advisor—Geophysical Engineering 

T. Nicholson Senior Technical Advisor—Radionuclide Transport 

R. Tregoning Senior Technical Advisor—Materials Engineering 

A. Hull Team Leader 
xxiv 

K. Arai Materials Engineering 

M. Benson Materials Engineering 

H. Candra Structural Engineering 

E. Focht Materials Engineering 

M. Fuhrman Geochemistry 

C. Harris Materials Engineering 

M. Hiser Materials Engineering 

M. Homiack Mechanical Engineering 

M. Kirk Materials Engineering 

B. Lin Mechanical Engineering 

S. Malik Materials Engineering 

K. Miller Electrical Engineering 

W. Norris Materials Engineering 

G. Oberson Materials Engineering 

R. Perkins Reliability & Risk Engineering 

I. Prokofiev Materials Engineering 

J. Philip Geotechnical Engineering 

A. Pulvirenti Materials Engineering 

S. Rao Materials Engineering 

M. Rossi Materials Engineering 

M. Sircar Structural Engineering 

M. Srinivasan Materials Engineering 

G. Stevens Materials Engineering 

D. Stroup Fire Protection Engineering 

J. Wallace Materials Engineering 

G. Wang Mechanical Engineering 

Center for Nuclear Waste Regulatory Analyses

G. Adams Computer Scientist/Industrial Engineering 

L. Howard Project Manager/Nuclear Engineering 

L. Naukam Program Support/Technical Editing 

Y. Pan Materials Engineering 

A. Ramos Program Support/Technical Editing 
xxv 

ABBREVIATIONS 

ACAR aluminum conductor aluminum alloy reinforced 

ACI American Concrete Institute 

ACSR aluminum conductor steel reinforced 

ADAMS Agencywide Documents Access and Management System 

AFW auxiliary feedwater 

ALE adverse localized environment 

AMPs aging management programs 

AMR aging management review 

ANSI American National Standards Institute 

ASME American Society of Mechanical Engineers 

ASME Code American Society of Mechanical Engineers Boiler and Pressure Vessel Code 

ASTM American Society for Testing and Materials 

ATWS anticipated transients without scram 

 

B&W Babcock & Wilcox 

BTP Branch Technical Position 

BWR boiling water reactor 

BWRVIP Boiling Water Reactor Vessel and Internals Project 

 

CASS cast austenitic stainless steel 

CE Combustion Engineering 

CFR Code of Federal Regulations 

CLB current licensing basis 

CRD control rod drive 

CRDM control rod drive mechanism 

CST condensate storage tanks 

CUF cumulative usage factor 

 

DBA design basis accident 

DBEs design basis events 

DOR Division of Operating Reactors 

 

ECCS emergency core cooling system 

EDG emergency diesel generator 

EFPY effective full power year 

EMA equivalent margins analysis 

EOL end-of-life 

EPDM ethylene propylene diene monosomer 

EPR ethylene propylene rubber 

EPRI Electric Power Research Institute 

EPU extended power uprate 

EQ Environmental Qualification 

 

FAC flow-accelerated corrosion 

FERC Federal Energy Regulatory Commission 

FP fire protection 

FR Federal Register 

FRN Federal Register Notice 
xxvi 

FSAR Final Safety Analysis Report 

FSER Final Safety Evaluation Report 

 

GALL Generic Aging Lessons Learned 

GALL-SLR Generic Aging Lessons Learned for Subsequent License Renewal 

GE General Electric 

GL generic letter 

GSI generic safety issue 

 

HELB high-energy line break 

HVAC heating, ventilation, and air conditioning 

 

I&C instrumentation and control 

IASCC irradiation-assisted stress corrosion cracking 

IEEE Institute of Electrical and Electronics Engineers 

IGSCC intergranular stress corrosion cracking 

IN information notice 

INPO Institute of Nuclear Power Operations 

IPA integrated plant assessment 

IPE individual plant examination 

IPEEE individual plant examination of external events 

ISG interim staff guidance 

ISI inservice inspection 

 

LBB leak-before-break 

LCOs limiting conditions for operation 

LOCA loss of coolant accident 

LRAs license renewal applications 

LWR light-water reactor 

 

MEB metal enclosed bus 

MIC microbiologically-induced corrosion 

MRP Materials Reliability Program 

 

NACE National Association of Corrosion Engineers 

NEI Nuclear Energy Institute 

NPS nominal pipe size 

NRC U.S. Nuclear Regulatory Commission 

NRR Office of Nuclear Reactor Regulation 

 

OE operating experience 

 

P&ID piping and instrumentation diagram 

PH precipitation-hardened 

PM Project Manager 

PRA Probabilistic Risk Analysis 

P-T pressure-temperature 

PTLRs pressure-temperature limit reports 

PTS pressurized thermal shock 

PVC polyvinyl chloride 

PWR pressurized water reactor 
xxvii 

PWSCC primary water stress corrosion cracking 

 

QA quality assurance 

 

RCIC reactor core isolation cooling 

RCP reactor coolant pump 

RCPB reactor coolant pressure boundary 

RG Regulatory Guide 

RIS Regulatory Issue Summary 

RPV reactor pressure vessel 

RV reactor vessel 

RVI reactor vessel internals 

RWST refueling water storage tank 

 

SBO station blackout 

SC structures and components 

SCC stress corrosion cracking 

SEEIN Significant Event Evaluation and Information Network 

SEs safety evaluations 

SER safety evaluation report 

SG steam generator 

SLR subsequent license renewal 

SLRA subsequent license renewal application 

SOC Statements of Consideration 

SOER significant operating experience report 

SRP standard review plan 

SRP-SLR Standard Review Plan for Review of Subsequent License Renewal 

Applications for Nuclear Power Plants 

SS stainless steel 

SSCs systems, structures, and components 

 

TGSCC transgranular stress corrosion cracking 

TLAAs time-limited aging analyses 

TRs technical or topical reports 

TS technical specifications 

 

UFSAR updated final safety analysis report 

USE upper-shelf energy 

USI unresolved safety issues 

UV ultraviolet 

 

XLPE cross-linked polyethylene 

xxix 

INTRODUCTION 

The Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear 

Power Plants (SRP-SLR) provides guidance to U.S. Nuclear Regulatory Commission (NRC) staff 

reviewers in the Office of Nuclear Reactor Regulation (NRR). These reviewers perform safety 

reviews of applications to renew nuclear power plant licenses in accordance with Title 10 of the 

Code of Federal Regulations (10 CFR) Part 54, “Requirements for Renewal of Operating Licenses 

for Nuclear Power Plant,” hereafter referred to as the Rule. The NRC regulations in 10 CFR 54.29 

establish the standards for issuance of a renewed license. For nuclear power plants that have 

received a renewed license, the regulations in 10 CFR 54.31(d) state that “a renewed license may 

be subsequently renewed in accordance with all applicable requirements.” The NRC has stated 

in the Statements of Consideration, “Nuclear Power Plant License Renewal,” 56 FR 64943, 

64964-65 (December 13, 1991), that the requirements for subsequent license renewal (SLR) 

“include the provisions of [P]art 54 (unless the Commission subsequently adopts special 

provisions applicable only to subsequent renewals).” To date, the NRC has not adopted special 

provisions that apply only to subsequent renewal, so that the requirements in 10 CFR Part 54 

continues to govern SLR. 

The principal purposes of the SRP-SLR are to ensure the quality and uniformity of the NRC staff 

review and to present a well-defined base from which to evaluate applicant programs and 

activities for the subsequent period of extended operation. The SRP-SLR also is intended to 

make regulatory information widely available to enhance communication with interested members 

of the public and the nuclear power industry and to improve their understanding of the NRC staff 

review process. 

The safety review is based primarily on the information provided by the applicant in a subsequent 

license renewal application (SLRA). The NRC regulation in 10 CFR 54.4 defines what is within 

the scope of the License Renewal Rule. The NRC regulation in 10 CFR 54.21 requires each 

application to include an integrated plant assessment, current licensing basis (CLB) changes 

during review of the application by the NRC, an evaluation of time-limited aging analyses (TLAAs), 

and a Final Safety Analysis Report supplement. 

In addition to the technical information required by 10 CFR 54.21, an SLRA must contain general 

information (10 CFR 54.19), necessary technical specification changes (10 CFR 54.22), and 

environmental information (10 CFR 54.23). The application must be sufficiently detailed to permit 

the reviewers to determine (i) whether there is reasonable assurance that the activities authorized 

by the renewed license will continue to be conducted in accordance with the CLB and (ii) whether 

any changes made to the plant’s CLB to comply with 10 CFR Part 54 are in accordance with the 

Atomic Energy Act of 1954 and NRC regulations. The technical information to be supplied in the 

SLRA is specified in 10 CFR 54.21. 

Before submitting an SLRA, an applicant should have analyzed the plant to ensure that actions 

have been or will be taken to (i) manage the effects of aging during the subsequent period of 

extended operation (this determination should be based on an assessment of the functionality of 

structures and components that are within the scope of SLR and that require an aging 

management review) and (ii) evaluate TLAAs. The SLRA is the principal document in which the 

applicant provides the information needed to understand the basis upon which the applicant has 

made this assurance. 
xxx 

The SRP-SLR references the Generic Aging Lessons Learned for Subsequent License Renewal 

(GALL-SLR) Report, which evaluates existing programs generically, to document (i) the conditions 

under which existing programs are considered adequate to manage identified aging effects 

without change and (ii) the conditions under which existing programs should be augmented for 

this purpose. The SRP-SLR also includes the NRC staff’s resolutions of License Renewal Interim 

Staff Guidance (LR-ISG) from 2011 through 2016 as listed below. 

 LR-ISG-2011-01: Aging Management of Stainless Steel Structures and Components in 

Treated Borated Water, Revision 1. Agencywide Documents Access and Management 

System (ADAMS) Accession No. ML12286A275. December 18, 2012. 

 LR-ISG-2011-02: Aging Management Program for Steam Generators. ADAMS 

Accession No. ML11297A085. December 1, 2011. 

 LR-ISG-2011-03: Generic Aging Lessons Learned (GALL) Report Revision 2 Aging 

Management Program (AMP) XI.M41, “Buried and Underground Piping and Tanks.” 

ADAMS Accession No. ML12138A296. August 2, 2012. 

 LR-ISG-2011-04: Updated Aging Management Criteria for Reactor Vessel Internal 

Components of Pressurized Water Reactors. ADAMS Accession No. ML12270A436. 

June 3, 2013. 

 LR-ISG-2011-05: Ongoing Review of Operating Experience. ADAMS Accession 

No. ML12044A215. March 16, 2012. 

 LR-ISG-2012-01: Wall Thinning Due to Erosion Mechanisms. ADAMS Accession 

No. ML12352A057. May 1, 2013. 

 LR-ISG-2012-02: Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation. ADAMS Accession 

No. ML13227A361. November 22, 2013. 

 LR-ISG-2013-01: Aging Management of Loss of Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks. 

ADAMS Accession No. ML14225A059. November 14, 2014. 

 LR-ISG-2015-01: Changes to Buried and Underground Piping and Tank 

Recommendations. ADAMS Accession No. ML15308A018. February 4, 2016. 

 LR-ISG-2016-01: Changes to Aging Management Guidance for Various Steam Generator 

Components. ADAMS Accession No. ML16237A383. December 7, 2016. 

Under the LR-ISG process the NRC staff, industry, or stakeholders can propose a change to 

certain license renewal guidance documents. The NRC staff evaluates the issue, develops 

proposed interim staff guidance (ISG), and issues an ISG for public comment. The NRC reviews 

any comments received, and, as appropriate, issues a final ISG. The ISG is then used until the 

NRC staff incorporates it into a formal license renewal guidance document revision. 

The GALL-SLR Report should be treated as an approved topical report. The NRC reviewers 

should not re-review a matter described in the GALL-SLR Report, but should find an application 

acceptable with respect to such a matter when the application references the GALL-SLR Report 
xxxi 

and when the evaluation of the matter in the GALL-SLR Report applies to the plant. However, 

reviewers should ensure that the material presented in the GALL-SLR Report is applicable to the 

specific plant involved and that the applicant has identified specific programs, as described and 

evaluated in the GALL-SLR Report, if they rely on the report for SLR. 

The SRP-SLR is divided into five major chapters: 

Chapter 1—Administrative Information 

Chapter 2—Scoping and Screening Methodology for Identifying Structures and Components 

Subject to Aging Management Review and Implementation Results 

Chapter 3—Aging Management Review Results 

Chapter 4—Time-Limited Aging Analyses 

Chapter 5—Technical Specifications Changes and Additions 

Appendix A to the SRP-SLR list branch technical positions and provides review guidance related 

to use of operating experience for aging management programs. The SRP-SLR addresses 

various site conditions and plant designs and provides complete procedures for all of the areas of 

review pertinent to each of the SRP-SLR sections. For any plant-specific application, NRC 

reviewers may select and emphasize particular aspects of each SRP-SLR section, as appropriate 

for the application. In some cases, the major portion of the review of a plant program or activity 

may be conducted on a generic basis (with the owners’ group of that plant type) rather than in the 

context of reviews of particular applications from utilities. In other cases, a plant program or 

activity may be sufficiently similar to that of a previous plant that a complete review of the program 

or activity is not needed. For these and similar reasons, reviewers need not carry out in detail all 

of the review steps listed in each SRP-SLR section in the review of every application. 

The individual SRP-SLR sections address: (i) which organization within the NRC staff performs 

the review; (ii) areas of review; (iii) the basis for review; (iv) the method of review; and (v) the 

conclusions from the review. One of the objectives of the SRP-SLR is to assign review 

responsibilities to the appropriate NRR branches. Each SRP-SLR section identifies the branch 

that has the primary review responsibility for that section. In some review areas, the primary 

branch may require support, the branches assigned these secondary review responsibilities also 

are identified for each SRP-SLR section. 

Each SRP-SLR section is organized into the following six subsections, generally consistent with 

NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants” (March 2007, with individual sections subsequently revised as needed). 

1. Areas of Review 

This subsection describes the scope of review, and contains a description of the systems, 

structures, components, analyses, data, or other information that is reviewed as part of the SLRA 

review. This subsection identifies the branch having the primary review responsibility and 

provides a discussion of the information needed or the review expected from other branches to 

permit the primary review branch to complete its review. 
xxxii 

2. Acceptance Criteria 

This subsection contains a statement of the purpose of the review, an identification of applicable 

NRC requirements, and the technical basis for determining the acceptability of programs and 

activities within the area of review of the SRP-SLR section. The technical bases consist of 

specific criteria, such as NRC regulatory guides, codes and standards, and branch 

technical positions. 

Consistent with the approach described in GALL-SLR Report, the technical bases for some 

sections of the SRP-SLR can be provided in branch technical positions or appendices as they are 

developed and can be included in the SRP-SLR. 

3. Review Procedures 

This subsection discusses the review methodology utilized by the NRC staff. It is generally a 

step-by-step procedure that the reviewer follows to verify that the applicable acceptance criteria 

have been met. 

4. Evaluation Findings 

This subsection presents the type of acceptable conclusion that may be reached for the particular 

review area (e.g., the reviewers’ determination as to whether the applicant has adequately 

identified the aging effects and the aging management programs credited with managing the 

aging effects). For each section, a conclusion of this type is included in the safety evaluation 

report (SER), in which the reviewers present the results of their review. The SER also contains a 

description of the review, including which aspects of the review were selected or emphasized; 

which matters were modified by the applicant, required additional information, items that will be 

resolved in the future, or remain unresolved; where the applicant’s program deviates from the 

criteria provided in the SRP-SLR; and the bases for any deviations from the SRP-SLR or 

exemptions from the regulations. 

5. Implementation 

This subsection discusses the NRC staff’s plans for using the SRP-SLR section. 

6. References 

This subsection lists the references used in the review process. 

The SRP-SLR incorporates the NRC staff experience in the review of license renewal 

applications. It may be considered a part of a continuing regulatory framework development 

activity that documents current methods of review and provides a basis for orderly modifications of 

the review process in the future. The SRP-SLR is revised and updated periodically, as needed, to 

incorporate experience gained during recent reviews, to clarify the content or correct errors, to 

reflect changes in relevant regulations, and to incorporate modifications approved by the NRR 

Division Director. Because individual sections will be revised as needed, the revision numbers 

and dates may not be the same for all sections. 
1.1-1 

1 ADMINISTRATIVE INFORMATION 

1.1 Docketing of Timely and Sufficient Renewal Application 

Review Responsibilities 

Primary—Branch responsible for subsequent license renewal projects 

Secondary—Branches responsible for technical review, as appropriate 

1.1.1 Areas of Review 

This section addresses (i) the review of the acceptability of a subsequent license renewal 

application (SLRA) for docketing in accordance with Title 10 of the Code of Federal Regulations

(10 CFR) 2.101 and the requirements of 10 CFR Part 54 and (ii) whether an application is timely 

and sufficient, which allows the provisions of 10 CFR 2.109(b) to apply. Application of this 

regulation, written to comply with the Administrative Procedures Act, means that the current 

license will not expire until the U.S. Nuclear Regulatory Commission (NRC) makes a final 

determination on the SLRA. 

The review described in this section is not a detailed, in-depth review of the technical aspects of 

the application. The docketing and subsequent finding of a timely and sufficient renewal 

application does not preclude the NRC staff from requesting additional information as the review 

progresses, and also does not imply the NRC’s final determination regarding the approval or 

denial of the renewal application. A plant’s current license will not expire upon the passing of the 

license’s expiration date if the renewal application was found to be timely and sufficient. During 

this time, and until a license renewal determination has been made by the NRC, the licensee must 

continue to perform its activities in accordance with the facility’s current licensing basis, including 

all applicable license conditions, orders, rules, and regulations. 

To determine whether an application is acceptable for docketing, the following areas of the SLRA 

are reviewed. 

1.1.1.1 Docketing and Sufficiency of Application 

The SLRA is reviewed for acceptability for docketing as a sufficient application in accordance with 

10 CFR 2.101, 10 CFR Part 51, and 10 CFR Part 54. 

1.1.1.2 Timeliness of Application 

The timeliness of an SLRA is reviewed in accordance with 10 CFR 2.109(b). 

1.1.2 Acceptance Criteria 

1.1.2.1 Docketing and Sufficiency of Application 

The NRC staff determines acceptance for docketing and sufficiency on the basis of the required 

contents of an application, established in 10 CFR 2.101, 10 CFR 51.53(c), 54.17, 54.19, 54.21, 

54.22, 54.23, 54.29 and 54.4. An application is sufficient if it contains the reports, analyses, and 

other documents required in such an application. 
1.1-2 

1.1.2.2 Timeliness of Application 

In accordance with 10 CFR 2.109(b), if the licensee of a nuclear power plant licensed under 

10 CFR 50.21(b) or 50.22 files a sufficient application for renewal of either an operating license or 

a combined license at least 5 years before the expiration of the existing license, the existing 

license will not be deemed to have expired until the application has been finally determined. 

1.1.3 Review Procedures 

A licensee may choose to submit plant-specific reports addressing portions of the License 

Renewal Rule requirements for NRC review and approval prior to submitting a renewal 

application. An applicant may incorporate (by reference) these reports or other information 

contained in previous applications for licenses or license amendments, statements, or 

correspondence filed with the NRC, provided that the references are clear and specific. However, 

the final determination of the sufficiency for docketing of a renewal application is made only after a 

formal SLRA has been submitted to the NRC. 

For each area of review, the NRC staff should implement the following review procedures. 

1.1.3.1 Docketing and Sufficiency of Application 

Upon receipt of a tendered application for subsequent license renewal (SLR), the reviewer should 

determine whether the applicant has provided the required administrative, technical, and 

environmental information. The reviewer should use the review checklist provided in Table 1.1-1 

to determine whether the application is reasonably complete and conforms to the requirements 

outlined in 10 CFR Part 54. 

Items I.1 through I.10 in the checklist address administrative information. For the purpose of this 

review, the reviewer checks the “Yes” column if the required information is included in the 

application. Item VI in the checklist addresses timeliness of the application. 

Items II, III, and IV in the checklist address scoping, technical information, the Final Safety 

Analysis Report supplement, and technical specification changes, respectively. Chapters 2, 3, 4, 

and 5 of the Standard Review Plan for Review of Subsequent License Renewal Applications for 

Nuclear Power Plants (SRP-SLR) provide information regarding the technical review. Although 

the purpose of the docketing and sufficiency review is not to determine the technical adequacy of 

the application, the reviewer should determine whether the applicant has provided reasonably 

complete information in the application to address the renewal rule requirements. The reviewer 

may request assistance from appropriate technical review branches to determine whether the 

application provides sufficient information to address the items in the checklist so that the NRC 

staff can begin their technical review. The reviewer should check the “Yes” column for a checklist 

item if the applicant has provided reasonably complete information in the application to address 

the checklist item. 

Item V of the checklist addresses environmental information. The environmental review by NRC 

staff reviews the supplement to the environmental report prepared by the applicant in accordance 

with the guidelines in NUREG–1555, “Standard Review Plans for Environmental Reviews for 

Nuclear Power Plants, Supplement 1: Operating License Renewal,” (Ref. 1). The reviewer 

checks the “Yes” column if the renewal application contains environmental information consistent 

with the requirements of 10 CFR Part 51. 
1.1-3 

The application should address each item in the checklist in order to be considered reasonably 

complete and sufficient. If the reviewer determines that an item in the checklist is not applicable, 

the reviewer should include a brief statement that the item is not applicable and provide the basis 

for the statement. 

If information in the application for a checklist item is either not provided or not reasonably 

complete and no justification is provided, the reviewer should check the “No” column for that 

checklist item. Except for Item VI as discussed in Subsection 1.1.3.2, checking any “No,” column 

indicates that the application is not acceptable for docketing as a sufficient renewal application 

unless the applicant modifies the application to provide the missing or incomplete information. 

If the reviewer concludes, and management concurs, that the application is not acceptable for 

docketing as a sufficient application, the letter (typically preceded by a management call between 

the NRC staff and the applicant) to the applicant should clearly state that (i) the application is not 

sufficient and is not acceptable for docketing and (ii) the current license will expire at its expiration 

date. The letter also should include a description of the deficiencies found in the application and 

offer an opportunity for the applicant to supplement its application to provide the missing or 

incomplete information. The reviewer should review the supplemented application, if submitted, to 

determine whether it is acceptable for docketing as a sufficient application. 

If the reviewer is able to answer “Yes” to the applicable items in the checklist, the application is 

acceptable for docketing as a sufficient renewal application. The applicant should be notified by 

letter that the application is accepted for docketing. Normally, the letter should be issued within 

30 days of receipt of a renewal application. A notice of acceptance for docketing of the 

application and notice of opportunity for a hearing regarding renewal of the license is published in 

the Federal Register. 

When the application is acceptable for docketing as a sufficient application, the NRC staff begins 

its technical review. For SLRAs, the NRC maintains the docket number of the current operating 

license for administrative convenience. 

1.1.3.2 Timeliness of Application 

If a sufficient application is submitted at least 5 years before the expiration of the current operating 

license, the reviewer checks the “Yes” column for Item VII in the checklist. If the supplemented 

application, as discussed in Subsection 1.1.3.1, is submitted at least 5 years before the expiration 

of the current operating license, the reviewer checks the “Yes” column for Item VI in the checklist. 

If the reviewer checks the “No” column in Item VI in the checklist, indicating that a sufficient 

renewal application has not been submitted at least 5 years before the expiration of the current 

operating license, the letter (typically preceded by a management call between the NRC staff and 

the applicant) to the applicant should clearly state that: (i) the application is not timely, (ii) the 

provisions in 10 CFR 2.109(b) have not been satisfied, and (iii) the current license will expire on 

the expiration date. The item in Section VI of the checklist is only included to determine if the 

application meets the criteria for timely renewal, not to determine the sufficiency of the application. 

Thus, if the application is otherwise determined to be acceptable for docketing, the technical 

review can begin. 
1.1-4 

1.1.4 Evaluation Findings 

The reviewer determines whether sufficient and adequate information has been provided to satisfy 

the provisions outlined in Section 1.1.3.1, “Docketing and Sufficiency of Application” above. 

Depending on the results of this review, one of the following conclusions is included in the NRC 

staff’s letter to the applicant: 

 On the basis of its review, as discussed above, the NRC staff has determined that the 

applicant has submitted sufficient information that is acceptable for docketing, in 

accordance with 10 CFR 54.19, 54.21, 54.22, 54.23, 54.4, and 51.53(c). However, the 

NRC staff’s determination does not preclude the request for additional information as the 

review proceeds. 

 On the basis of its review, as discussed above, the NRC staff has determined that the 

application is not acceptable for docketing as a timely and/or sufficient renewal application.

1.1.5 Implementation 

NRC staff follows the methods described above to evaluate the sufficiency of the application 

for docketing. 

1.1.6 References 

1. NRC. NUREG–1555, “Standard Review Plans for Environmental Reviews for Nuclear 

Power Plants, Supplement 1: Operating License Renewal.” Revision 1. Agencywide 

Documents Access and Management System (ADAMS) Accession No. ML13106A246. 

Washington, DC: U.S. Nuclear Regulatory Commission. June 2013. 
1.1-5 

Table 1.1-1 Acceptance Review Checklist for Subsequent License Renewal 

Application Acceptability for Docketing 

 Yes No 

I. General Information 

 1. Application identifies specific unit(s) applying for subsequent license 

renewal 

 2. Filing of renewal application 10 CFR 54.17(a) is in accordance with: 

 A. 10 CFR Part 2, Subpart A; 10 CFR 2.101 

 B. 10 CFR 50.4 

 a. Application is addressed to the Document Control Desk as 

specified in 10 CFR 50.4(a) 

 b. A signed original application and hard copies are provided 

to the Document Control Desk. One copy is provided to 

the appropriate Regional Office and one copy to the 

Regional Inspectors in accordance with the NRC 

docketing requirement in 10 CFR 50.4. 

 c. Form of the application meets the requirements of 

10 CFR 50.4(c) 

 C. 10 CFR 50.30 

 a. Application is filed in accordance with 10 CFR 50.4 

[10 CFR 50.30(a)(1)] 

 b. Application is submitted under oath or affirmation 

[10 CFR 50.30(b)] 

 3. Applicant is eligible to apply for a license and is not a foreign-owned 

or foreign-controlled entity [10 CFR 54.17(b)] 

 4. Application is not submitted earlier than 20 years before expiration of 

current license [10 CFR 54.17(c)] 

 5. Application states whether it contains applications for other kinds of 

licenses [10 CFR 54.17(d)] 

 6. Information incorporated by reference in the application is contained 

in other documents previously filed with the Commission, and the 

references are clear and specific [10 CFR 54.17(e)] 

 7. Restricted data or other defense information, if any, is separated 

from unclassified information in accordance with 10 CFR 50.33(j) 

[10 CFR 54.17(f)] 

 8. If the application contains restricted data, written agreement on the 

control of accessibility to such information is provided 

[10 CFR 54.17(g)] 

 9. Information specified in 10 CFR 50.33(a) through (e), (h), and (i) is 

provided or referenced [10 CFR 54.19(a)]: 

 A. Name of applicant 

 B. Address of applicant 

 C. Business description 

 D. Citizenship and ownership details 

 E. License information 

 F. Construction or alteration dates 

 G. Regulatory agencies and local publications 

 10. Conforming changes, as needed, to the standard indemnity 

agreement have been submitted (10 CFR 140.92, Appendix B) to 

account for the proposed change in the expiration date 

[10 CFR 54.19(b)] 
1.1-6 

Table 1.1-1. Acceptance Review Checklist for Subsequent License Renewal 

Acceptability for Docketing (Continued)

 Yes No 

ll. Technical Information 

 1. An integrated plant assessment [10 CFR 54.21(a)] is provided, and 

consists of: 

 

 A. For those systems, structures, and components (SSCs) within 

the scope of license renewal (10 CFR 54.4), identification and 

listing of those SCs that are subject to an aging management 

review (AMR) in accordance with 10 CFR 54.21(a)(1)(i) and (ii) 

 

 a. Description of the boundary of the system or structure 

considered (if applicant initially scoped at the system or 

structure level). Within this boundary, identification of 

structures and components (SCs) subject to an AMR. For 

commodity groups, description of basis for the grouping 

 b. Lists of SCs subject to an AMR 

 B. Description and justification of methods used to identify SCs 

subject to an AMR [10 CFR 54.21(a)(2)] 

 C. Demonstration that the effects of aging will be adequately 

managed for each structure and component identified, so that 

their intended function(s) will be maintained consistent with the 

current licensing basis for the period of extended operation 

[10 CFR 54.21(a)(3)] 

 

 a. Description of the intended function(s) of the SCs 

 b. Identification of applicable aging effects based on 

materials, environment, operating experience, etc. 

 c. Identification and description of aging management 

programs (AMP) 

 d. Demonstration of aging management provided 

 2. An evaluation of time-limited aging analysis (TLAAs) is provided, and 

consists of: 

 

 A. 

B. 

Listing and description of plant-specific TLAAs in accordance 

with the six criteria specified in 10 CFR 54.3 

[10 CFR 54.21(c)(1)] 

An evaluation of each identified TLAA using one of the three 

approaches specified in 10 CFR 54.21(c)(1)(i) to (iii) 

 3. All plant-specific exemptions granted pursuant to 10 CFR 50.12 and 

in effect that are based on a TLAA are listed, and evaluations 

justifying the continuation of these exemptions for the subsequent 

period of extended operation are provided [10 CFR 54.21(c)(2)] 

 A. Listing of plant-specific exemptions that are based on TLAAs 

as defined in 10 CFR 54.3 [10 CFR 54.21(c)(2)] 

 B. An evaluation of each identified exemption justifying the 

continuation of these exemptions for the subsequent period of 

extended operation [10 CFR 54.21(c)(2)] 
1.1-7 

Table 1.1-1. Acceptance Review Checklist for Subsequent License Renewal 

Acceptability for Docketing (Continued)

 Yes No 

III An FSAR Supplement [10 CFR 54.21(d)] is provided and contains the 

following information: 

 

 1. Summary description of the AMPs and activities for managing the 

effects of aging 

 2. Summary description of the evaluation of TLAAs 

IV. Technical Specification Changes 

 Any technical specification changes necessary to manage the aging 

effects during the period of extended operation and their justifications are 

included in the application (10 CFR 54.22) 

V. Environmental Information 

 Application includes a supplement to the environmental report that is in 

accordance with the requirements of Subpart A of 10 CFR Part 51 

(10 CFR 54.23) 

VI. Timeliness Provision 

 The application is sufficient and submitted at least 5 years before 

expiration of current license [10 CFR 2.109(b)]. If not, application can be 

accepted for docketing, but the timely renewal provision in 

10 CFR 2.109(b) does not apply 

VII. Conclusions Regarding Acceptance of Application for Docketing 

 The application is reasonably complete and meets the Acceptance 

Review Checklist criteria I through V and is recommended for docketing 

1.2-1 

1.2 Integrated Plant Assessments and Aging Management Reviews 

The U.S. Nuclear Regulatory Commission (NRC) Project Manager (PM) responsible for the safety 

review of the subsequent license renewal application (SLRA) is responsible for assigning to 

appropriate NRC Office of Nuclear Reactor Regulation divisions the review or audit of aging 

management reviews (AMRs) of systems, structures and components (SSCs) or aging 

management programs (AMPs) identified in the applicant’s SLRA. The PM documents to which 

organization each AMR or AMP is assigned. The assigned AMRs and AMPs are reviewed per 

the criteria described in Sections 3.1 through 3.6 of this Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR), for review of 

SLRAs, as directed by the scope of each of these sections. Chapter 4 of this standard review 

plan (SRP) provides guidelines for using time-limited aging analyses (TLAAs) as the basis for 

evaluating and managing aging effects by analysis. Specifically, Section 4.1 of this SRP-SLR 

provides the NRC staff’s guidance for identifying TLAAs in accordance with the requirements in 

Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1) and the definitions of TLAAs in 

10 CFR 54.3. TLAAs are reviewed in accordance with the acceptance criteria and guidance 

described in Sections 4.2 through 4.7 of this SRP. 

Review of the AMPs requires assessment of 10 program elements as defined in this SRP-SLR. 

The NRC division assigned the AMP reviews the 10 program elements to verify their technical 

adequacy. For 3 of the 10 program elements (corrective actions, confirmation process, and 

administrative controls), the NRC division responsible for review of the quality assurance (QA) 

aspects of the application verifies that the applicant has documented a commitment in the Final 

Safety Analysis Report (FSAR) Supplement to expand the scope of its 10 CFR Part 50, 

Appendix B program to address the associated program elements for each AMP. If the applicant 

chooses alternate means of addressing these three program elements, (i.e., use of a process 

other than the applicant’s 10 CFR Part 50, Appendix B program) the NRC division assigned to 

review the AMP should request that the division responsible for QA review the applicant’s 

proposal on a case-specific basis. 

1.2.1 Background on the Types of Reviews 

Section 54.21(a)(3) to 10 CFR Part 54 requires the application to demonstrate, for SSCs within 

the scope of license renewal and subject to an AMR pursuant to 10 CFR 54.21(a)(1), that the 

effects of aging are adequately managed so that the intended function(s) are maintained 

consistent with the current licensing basis (CLB) for the subsequent period of extended operation. 

This AMR consists of identifying the material, environment, aging effects, and the AMP(s) credited 

for managing the aging effects. 

Sections 3.1 through 3.6 of this SRP-SLR describe how the AMRs and AMPs are reviewed. In 

this SRP-SLR, Subsection 3.X.2 (where X denotes number 1–6) presents the acceptance criteria 

describing methods to determine whether the applicant has met the requirements of the NRC’s 

regulations in 10 CFR 54.21. Subsection 3.X.3 presents the review procedures to be followed.

The AMR line items in the 3.X-1 tables provide a generic list of AMRs for groups of components 

that may be included in the reactor coolant system, emergency safety feature systems, auxiliary 

systems, steam and power conversion systems, structures and structural components, and 

electrical systems of an applicant’s pressurized water reactor (PWR) or boiling water reactor 

(BWR) plant design. The AMR items are provided in a column-based format that accomplishes 

the following objectives: 
1.2-2 

 New (N), Modified (M), Deleted (D), Edited (E) Item: The description of this column 

identifies whether the AMR line item is new, was modified, deleted, or edited. The NRC 

will publish the technical bases for these new, modified, and deleted AMR items in a 

NUREG containing the disposition of public comments and the technical bases for 

changes in the guidance documents after the final subsequent license renewal (SLR) 

guidance documents are published. 

 “ID” column: The description for this column provides an identification number for the 

AMR item of a given commodity grouping of components that have common materials of 

fabrication, environmental conditions, and aging effects. 

 “Type” column: The description for this column identifies whether the specific AMR item in 

the table is applicable to BWR, PWR, or both plant designs. 

 “Component” column: The description for this column identifies the specific components 

that are within the scope of the commodity grouping in the AMR item and the materials of 

fabrication and environmental conditions that are applicable to the components in the 

AMR item. 

 “Aging Effect/Mechanism” column: The description for this column identifies the aging 

effects and mechanisms that are applicable to the material-environmental combinations for 

the components in the commodity grouping of the AMR item. 

 “Aging Management Program/TLAA” column: The description for this column provides 

AMPs or TLAAs that may be used to manage the aging effects that apply to the 

components in the commodity grouping of the AMR item and to demonstrate compliance 

with the aging management requirement in 10 CFR 54.21(a)(3). 

 “Further Evaluation” column: The description for this column identifies whether the AMP 

or TLAA recommended in the “Aging Management Program/TLAA” column of the AMR 

item requires additional evaluation (further evaluation) by an applicant adopting the AMR 

item. This column also references the specific subsection(s) in SRP-SLR Chapter 3 

applicable to the evaluation of the components in the commodity grouping of the 

AMR item. 

 “GALL-SLR Item” column: The description for this column identifies the 

component-specific AMR items in the Generic Aging Lessons Learned for Subsequent 

License Renewal (GALL-SLR) Report that derives from the commodity-group-based item 

in the SRP-SLR AMR table. 

Edited (E) items, in contrast to modified (M) items, are those for which no technical aspects were 

changed. Examples of editorial changes include: 

 Line item citations that were missed in the SRP-SLR Table 3.X-1. 

 Deleting whether the environment is internal or external from the description of the 

environment because based on the material, environment, aging effect, and AMP 

combination, it is obvious that the environment could only be on either the inside or 

outside of the component. 
1.2-3 

 Deletion of the term “piping element” from aging management review items that do not cite 

glass as a material. Piping elements are defined in the GALL-SLR Report as components 

constructed of glass. 

 Line item changes that only involved removing detail related to a Further Evaluation 

Recommended column was removed after it was verified that the identical information was 

included in the SRP-SLR further evaluation section. 

 Line item changes that only involved renumbering further evaluation sections. 

 Aging effects changed from “and” to “or.” This could appear to be a technical change; 

however, this is not the case because the staff confirmed that is was never the intent that 

both aging effects were occurring. For example, the “and” in cracking due to stress 

corrosion cracking and cyclic loading was replaced with “or.” 

 Deleting the term “environment” from the description of the environment in the 

“Environment” column when the phrase “any environment” was used because it was 

obvious and redundant. 

 Descriptors for the AMPs in the “Aging Management Program/TLAA” column were 

simplified if the information was provided elsewhere. 

 Minor edits to component descriptions, examples (a) deleting “elastomer” from “elastomer, 

elastomer seals;” (b) adding “piping” or “ducting” in front of the term “component.” 

 Adding the term “electrical” to Structure and/or Component and Aging Effect/Mechanism 

description. 

The GALL-SLR Report is a technical basis document to the SRP-SLR and provides generic AMR 

and AMP guidance that may be used as part of the bases for developing an SLRA. As such, the 

GALL-SLR Report contains an acceptable method that may be used to assist an applicant in: 

(a) developing the integrated plant assessment (IPA) for an SLRA, as required by 

10 CFR 54.21(a); (b) identifying those components and structures that are required to be within 

the scope of an AMR, as required by 10 CFR 54.21(a)(1); and (c) managing those aging effects 

that are applicable to these SSCs, as required by 10 CFR 54.21(a)(3). An applicant may propose 

an alternative method for performing the IPA. Therefore, the use of the GALL-SLR Report is not 

required; however, its use should facilitate both preparation of an SLRA by an applicant and 

timely, uniform review by the NRC staff. If the GALL-SLR Report is used for the development of 

an SLRA, the GALL-SLR Report should be treated as an NRC-approved topical report. 

The GALL-SLR Report contains an AMR evaluation of a large number of structures and 

components (SCs) that may be in the scope of a typical SLRA and may need to be the subject of 

an AMR in accordance with requirements in 10 CFR 54.21(a)(1). The AMR results documented 

in the GALL-SLR Report indicate that many existing, typical generic AMPs are adequate to 

manage aging effects for particular structures or components without change. The GALL-SLR 

Report also contains recommendations on specific areas for which generic existing programs 

should be augmented for SLRAs and documents the technical basis for each such determination. 

In addition, the GALL-SLR Report identifies certain SCs that may or may not be subject to 

particular aging effects, and for which industry groups are developing generic AMPs or 

investigating whether aging management is warranted. The ultimate generic resolution of such an 

issue may need NRC review and approval for plant-specific implementation, as indicated in a 
1.2-4 

plant-specific FSAR supplement, and reflected in the safety evaluation report (SER) associated 

with a particular SLRA. 

The GALL-SLR Report does not address scoping of SSCs for SLR. The determination of SSCs 

that need to be within the scope of SLR is plant-specific aspect of the application and is required 

to be performed in accordance with the requirements in 10 CFR 54.4. Consistent with the scoping 

guidelines in Chapter 2 of this SRP-SLR, the scoping results for an SLRA are dependent on the 

plant design and CLB. Therefore, the inclusion of a certain structure or component in a given 

AMR line item of the GALL-SLR Report does not mean that this particular structure or component 

is within the scope of SLR for all plants. 

Conversely, the omission of a certain structure or component in the GALL-SLR Report does not 

mean that a particular structure or component in the plant design is not within the scope of the 

SLRA or does not need to be the subject of an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1). The AMR line items in the SRP-SLR and GALL-SLR Report may not provide 

a comprehensive list of all structures of components that need to be within the subject of an AMR 

or a comprehensive list of all potential aging effects that may be applicable to those structures or 

components as being the subject of an AMR. Therefore, as has been the practice for initial 

license renewal applications, plant-specific AMRs should be performed if additional aging effects 

(not referenced in the SRP-SLR and GALL-SLR Report) are applicable to the design of a specific 

structure or component subject to an AMR. 

As indicated in the bulleted list above, the specific AMR line items in Chapters II–VIII of the 

GALL-SLR Report derive from and are identified in the AMR line items of the 3.X-2 tables of the 

SRP-SLR. The AMR line items in GALL-SLR Report are formatted in a manner that is analogous 

(but not identical) to the format of the AMR line items in the SRP-SLR. In addition, as indicated 

above, the “Further Evaluation” column in the AMR line items of the 3.X-1 tables of this report and 

the AMR tables (Chapters II through VIII of the GALL-SLR Report) establish whether the aging 

management bases in those AMR line items need to be the subject of further assessment by the 

applicant (i.e., the subject of “further evaluations”). The “further evaluation” topics and the 

acceptance criteria for satisfying these “further evaluations” are described in the 3.X.2.2 

subsections of this report. The related review procedures for these “further evaluation” topics are 

provided in the 3.X.3.2 subsections of this report. 

Therefore, for SCs in the plant design that are required to be scoped into the SLRA and subject to 

an AMR, the applicant may use the AMR line items in the 3.X-1 tables of the SRP-SLR, and the 

AMR line items in the GALL-SLR Report referenced in these SRP-SLR tables, as a basis for 

comparison to the design of the SCs in the plant design. If this method is used for development of 

the AMR, the applicant may adopt those AMR items in the SRP-SLR and GALL-SLR Reports that 

are applicable to the design of the SCs in the plant in order to aid the applicant in identifying those 

aging effects that are applicable to the structures or components. For those AMR items in the 

SLRA that are designated as being consistent with the SRP-SLR and GALL-SLR Report and are 

the subject of “further evaluation” aging management topics, the AMR should include the 

applicant’s bases on how those “further evaluation” criteria have been addressed and met, as 

applicable to the licensing basis and design basis for the plant’s design. 

As part of the development of the SLRA, the applicant should assess the AMPs in the GALL-SLR 

Report. The applicant may choose to use an AMP that is consistent with the GALL-SLR Report 

AMP, or may choose a plant-specific AMP. An applicant may reference the GALL-SLR Report in 

an SLRA to designate which programs at the applicant’s facility will be used to manage the effects 

of aging for specific structures or components, and how those programs correspond to the AMPs 
1.2-5 

reviewed and approved in the GALL-SLR Report. If an applicant does take credit for a program in 

the GALL-SLR Report, it is incumbent on the applicant to ensure that the conditions and operating 

experience (OE) at the plant is bounded by the conditions and OE for which the GALL-SLR 

Report program was evaluated. If these bounding conditions are not met it is incumbent on the 

applicant to address the additional effects of aging and augment the AMP(s) in the GALL-SLR 

Report in the SLRA, as appropriate. 

If a GALL-SLR Report AMP is selected to manage aging, the applicant may take one or more 

exceptions to specific GALL-SLR Report AMP program elements. Exceptions are portions of the 

GALL‐SLR Report AMP that the applicant does not intend to implement, which the staff will review 

on a case-by-case basis. Any deviation or exception to the GALL-SLR Report AMP should be 

described and justified. The applicant may identify that the exception was previously approved for 

the plant under review. The applicant may also use precedence from another plant to justify their 

exception. In both these cases, the reviewer is to confirm that the justifications for the previously 

approved exceptions are acceptable for the subsequent period of extended operation. For 

example, a previously approved exception may have been acceptable for operation up to 

60 years, but not past 60 years. 

In some cases, an applicant may choose an existing plant program that does not currently meet 

all the program elements defined in the GALL-SLR Report AMP. If this is the situation, the 

applicant makes a commitment to augment the existing program to satisfy the GALL-SLR Report 

AMP elements prior to the subsequent period of extended operation. 

Enhancements are revisions or additions to existing AMPs that the applicant commits to 

implement prior to the subsequent period of extended operation. Enhancements include, but are 

not limited to, those activities needed to ensure consistency with the GALL-SLR Report 

recommendations. Enhancements may expand, but not reduce, the scope of an AMP. 

For the programs submitted in the SLRA that the applicant claims are consistent with the 

GALL-SLR Report, the NRC staff will verify that the applicant’s programs are consistent with those 

described in the GALL-SLR Report and/or with plant conditions and OE during the performance of 

an AMP audit and review. The focus of the balance of the NRC staff review of an SLRA is on 

those programs that an applicant has enhanced to be consistent with the GALL-SLR Report, 

those programs for which the applicant has taken an exception to the program described in the 

GALL-SLR Report, and plant-specific programs not described in the GALL-SLR Report. 

An audit and review is conducted at the applicant’s facility to evaluate AMPs that the applicant 

claims to be consistent with the GALL-SLR Report. The applicant may use a plant-specific AMP 

or plant-specific aging management activities as the basis for aging management of a specific 

structure or component. If plant-specific AMPs or aging management activities are used as the 

basis for aging management, the NRC staff reviews the AMPs or activities in accordance with the 

program element criteria that are defined in the SRP-SLR Appendix A.1, Subsection A.1.2.3. 

Reviews are also performed to address those AMRs or AMPs related to emergent issues, stated 

to be not consistent with the GALL-SLR Report, or based on an NRC-approved precedent 

(e.g., AMRs and AMPs addressed in an NRC SER of a previous SLRA) or technical or topical 

report (TR). SRP-SLR Section 1.2.3 provides additional guidance on reviewing those 

GALL-based or plant-specific AMPs that are based on NRC-endorsed TRs. As a result of the 

criteria established in 10 CFR Part 54, the guidance provided in SRP-SLR, GALL-SLR Report, 

and the applicant’s exceptions and/or enhancements to a GALL-SLR Report AMP, the following 

aspects of the SLRA are audited or reviewed by the NRC staff. 
1.2-6 

AMRs 

 AMR results consistent with the GALL-SLR Report 

 AMR results for which further evaluation is recommended 

 AMR results not consistent with or not addressed in the GALL-SLR Report 

AMPs 

 Consistent with the GALL-SLR Report AMPs 

 Plant-specific AMPs 

TLAAs 

FSAR Supplement 

 The regulation in 10 CFR 54.21(d) requires the SLRA to include a FSAR Supplement 

summary description for each AMP or aging management activity and each TLAA that is 

included in the SLRA. 

 The renewed license will include a license condition that will specifies the time for 

incorporating the contents of its FSAR Supplement into the FSAR as specified in 

10 CFR 50.71(e). This includes incorporation of all FSAR Supplement summary 

descriptions that were included in the FSAR Supplement for AMPs, aging management 

activities, and TLAAs included in the SLRA, and any programmatic or TLAA-related 

enhancements or commitments that may have been included in the FSAR Supplement, 

including those for implementing the AMPs, aging management activities and TLAAs 

during the subsequent period of extended operation. 

1.2.2 Applications With Approved Extended Power Uprates 

Extended power uprates (EPUs) are licensing actions that some licensees have recently 

requested the NRC staff to approve. This can affect aging management. In an NRC staff letter to 

the Advisory Committee on Reactor Safeguards, dated October 26, 2004, (Agencywide 

Documents Access and Management System (ADAMS) Accession No. ML042790085), the NRC 

Executive Director for Operation states that “All license renewal applications with an approved 

EPU will be required to perform an OE review and its impact on AMPs for SCs before entering the 

subsequent period of extended operation.” One way for an applicant with an approved EPU to 

satisfy this criterion is to document its commitment to perform an OE review and its impact on 

AMPs for SSCs before entering the subsequent period of extended operation as part of its SLRA. 

Such licensee commitments should be documented in the NRC staff’s SER, written in support of 

issuing a renewed license. The NRC staff expects to impose a license condition on any renewed 

license to ensure that the applicant completes these activities no later than the committed date. 

EPU impact on SSCs should be part of the SLR review. If necessary, the PM assigns a 

responsible group to address EPU. 

1.2.3 Aging Management Programs That Rely on Implementation of Nuclear Regulatory 

Commission-Approved Technical or Topical Reports 

The NRC Office Instruction LIC-500, Revision 5, establishes the NRC’s current process 

expectations for applying the methodology in an NRC-endorsed or NRC-approved technical or 

topical report (TR) to the CLB or current design basis of a licensed U.S. light-water reactor facility. 
1.2-7 

The LIC-500 office instruction identifies that the use of such reports may be subject to specific 

limitations or actions, which are identified and issued in the NRC’s safety evaluations (SEs) that 

evaluate the TR methodologies. The LIC-500 office instruction states that it is the NRC’s 

expectation that licensees or applicants applying these types of reports to their CLBs or design 

bases will address or respond to those action items or limitations that were issued in the NRC 

staff’s SEs regarding the TR methodologies. 

Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report AMPs that 

rely on the recommended activities in NRC-endorsed TRs identifies those TRs that are within the 

scope of the AMPs. Examples of GALL-SLR Report AMPs that rely on NRC-approved industry 

reports include, but are not limited to: (1) GALL-SLR Report AMP XI.M4, “BWR Vessel ID 

Attachment Welds,” (2) GALL-SLR Report AMP XI.M8, “BWR Penetrations,” and (3) GALL-SLR 

Report AMP XI.M9, “BWR Vessel Internals.” Plant-specific AMPs may also be based on 

NRC-approved TRs. 

For AMPs that rely on one or more NRC-endorsed TRs, the use of TR methodologies that are 

relied upon for aging management is subject to the applicant’s bases for resolving any limitations 

or action items that are placed on implementation of the applicable TR methodologies. Therefore, 

an applicant’s bases for resolving any limitations or actions items on the TRs is especially relevant 

to the applicant’s determination on whether the scope of the program, or other program elements 

in the AMP, will need to be augmented or enhanced beyond conformance with the recommended 

criteria, evaluations, and activities in the applicable TRs. Therefore, the AMPs should include the 

applicant’s bases for resolving any limitation or action items on the applicable TR methodologies, 

as documented in the NRC SE regarding the methodologies. If it is determined that the basis 

for resolving a specific TR limitation or applicant action item would result in the need for 

augmentation of the AMP beyond the criteria, evaluations, or activities recommended in the TRs, 

the applicant should enhance its AMPs accordingly to identify the TR guidance protocols or 

activities that will be impacted and the specific AMP program elements that will need to be 

enhanced or adjusted (as necessary and applicable to the CLB and design basis for the facility) 

as a result of the applicant’s basis for resolving the specific limitation or action item. Consistent 

with the recommendations in Nuclear Energy Institute 95-10, as referenced by Regulatory 

Guide 1.188, applicants may provide their bases for resolving the specific limitations or action 

items in Appendix C of their SLRAs. 

In addition, for AMPs that rely on these types of TRs, the recommended activities in these TRs 

may go beyond those activities that are within the scope of applicable NRC requirements 

(e.g., those requirements in any of the applicable Federal Acts, NRC regulations, plant operating 

license or technical specification requirements, or NRC-issued orders). Implementation of the 

TRs referenced in the AMPs does not relieve the applicant from complying with the applicable 

requirements, unless applicable Code reliefs, regulatory exemptions, or notices of enforcement 

discretion are requested and granted by the NRC for the specific type of requirement that applies 

to the CLB. This is in addition to those aspects of the 10 CFR Part 50, Appendix B program that 

may apply to the AMPs.

2.1-1 

2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING 

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW AND IMPLEMENTATION RESULTS 

2.1 Scoping and Screening Methodology 

Review Responsibilities 

Primary—Assigned branch(es) 

Secondary—None 

2.1.1 Areas of Review 

This section addresses the scoping and screening methodology for subsequent license renewal 

(SLR). As required by Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(2), the 

applicant, in its integrated plant assessment (IPA), is to describe and justify methods used to 

identify systems, structures, and components (SSCs) subject to an aging management review 

(AMR). The SSCs subject to AMR are those that perform an intended function, as described in 

10 CFR 54.4, and meet two criteria in 10 CFR 54.21(a)(1)(i) and (ii). The two criteria are those 

structures and components (SCs): 

1. That perform an intended function, as described in § 54.4, without moving parts or 

without a change in configuration or properties 

2. That are not subject to replacement based on a qualified life or specified time period 

Such SCs are denoted as “passive,” “long-lived” in this standard review plan. 

The identification of the SSCs within the scope of SLR is called “scoping.” For those SSCs within 

the scope of SLR, the identification of “passive,” “long-lived” SCs that are subject to an AMR is 

called “screening.” 

To verify that the applicant has properly implemented its methodology, the U.S. Nuclear 

Regulatory Commission (NRC) staff reviews the implementation results separately, following the 

guidance in Sections 2.2 through 2.5. 

The following areas relating to the applicant’s scoping and screening methodology are reviewed. 

2.1.1.1 Scoping 

The methodology used by the applicant to implement the scoping requirements of 10 CFR 54.4, 

“Scope,” is reviewed. 

2.1.1.2 Screening 

The methodology used by the applicant to implement the screening requirements of 

10 CFR 54.21(a)(1) is reviewed. 
2.1-2 

2.1.2 Acceptance Criteria 

The acceptance criteria for the areas of review are based on the following regulations: 

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

 10 CFR 54.4(b) as it relates to the identification of the intended functions of plant SSCs 

determined to be within the scope of the Rule 

 10 CFR 54.21(a)(1) and (a)(2) as they relate to the methods utilized by the applicant to 

identify plant SCs subject to an AMR 

Specific criteria necessary to determine whether the applicant has met the relevant requirements 

of 10 CFR 54.4(a), 54.4(b), 54.21(a)(1), and 54.21(a)(2) are as follows. 

2.1.2.1 Scoping 

The scoping methodology used by the applicant should be consistent with the process described 

in Section 3.0, “Identify the SSCs within the Scope of License Renewal and Their Intended 

Functions,” of Nuclear Energy Institute (NEI) 95-10, “Industry Guideline for Implementing the 

Requirements of 10 CFR Part 54—The License Renewal Rule” (Ref. 1), as referenced by 

Regulatory Guide (RG) 1.188, or the justification provided by the applicant for any exceptions 

should provide a reasonable basis for the exception. 

2.1.2.2 Screening 

The screening methodology used by the applicant should be consistent with the process 

described in Section 4.1, “Identification of Structures and Components Subject to an Aging 

Management Review and Intended Functions,” of NEI 95-10 (Ref. 1), as referenced by RG 1.188. 

2.1.3 Review Procedures 

Preparation for the review of the scoping and screening methodology employed by the applicant 

should include review of the following sources of information: 

 The safety evaluation report (SER) that was issued on the facility’s license renewal. This 

review is conducted for the purpose of familiarization with the principal design criteria for 

the facility and its current licensing basis (CLB), as defined in 10 CFR 54.3(a). 

 Chapters 1 through 12 of the updated final safety analysis report (UFSAR) and the 

facility’s technical specifications for the purposes of familiarization with the facility design 

and the nomenclature that is applied to SSCs within the facility (including the bases for 

such nomenclature). During this review, the SSCs should be identified that are relied 

upon to remain functional during and after design basis events (DBEs), as defined in 

10 CFR 50.49(b)(1)(ii), for which the facility was designed, to ensure that the functions 

described in 10 CFR 54.4(a)(1) are successfully accomplished. This review should also 

yield information regarding seismic Category I SSCs as defined in RG 1.29, “Seismic 

Design Classification for Nuclear Power Plants” (Ref. 2). For a newer plant, this 

information is typically contained in Section 3.2.1, “Seismic Classification,” of the UFSAR 

consistent with the Standard Review Plan (NUREG–0800) (Ref. 3). 
2.1-3 

 Chapter 15 (or equivalent) of the UFSAR to identify the anticipated operational 

occurrences and postulated accidents that are explicitly evaluated in the accident analyses 

for the facility. During this review, the SSCs that are relied upon to remain functional 

during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the functions 

described in 10 CFR 54.4(a)(1) should be identified. 

 The set of DBEs as defined in the Rule is not limited to Chapter 15 (or equivalent) of the 

UFSAR. Examples of DBEs that may not be described in this chapter include external 

events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal 

events, such as a high-energy line break. Information regarding DBEs as defined in 

10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the Commission’s 

regulations, NRC orders, exemptions, or license conditions within the CLB. These 

sources should also be reviewed to identify SSCs that are relied upon to remain functional 

during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the functions 

described in 10 CFR 54.4(a)(1). 

 The facility’s Probabilistic Risk Analysis (PRA) Summary Report that was prepared by the 

licensee in response to Generic Letter (GL) 88-20, “Individual Plant Examination for 

Severe Accident Vulnerabilities–10 CFR 50.54(f),” dated November 23, 1988 (Ref. 4). 

This review should yield additional information regarding the impact of the individual plant 

examination (IPE) on the CLB for the facility. While the License Renewal (LR) Rule is 

“deterministic,” the NRC in the Statements of Consideration (SOC) accompanying the 

Rule also states that “In license renewal, probabilistic methods may be most useful, on a 

plant-specific basis, in helping to assess the relative importance of structures and 

components that are subject to an AMR by helping to draw attention to specific 

vulnerabilities [e.g., results of an IPE or (individual plant examination of external events) 

IPEEE]” (60 FR 22468). For example, the reviewer should focus on IPE information 

pertaining to plant changes or modifications that are initiated by the licensee in 

accordance with the requirements of 10 CFR 50.59 or 10 CFR 50.90. 

 The results of the facility’s IPEEE study conducted as a follow-up to the IPE performed as 

a result of GL 88-20 to identify any changes or modifications made to the facility in 

accordance with the requirements of 10 CFR 50.59 or 10 CFR 50.90. 

 The applicant’s docketed correspondence related to the following regulations: 

 (a) 10 CFR 50.48, “Fire Protection” 

(b) 10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to 

Safety for Nuclear Power Plants” 

(c) 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against 

Pressurized Thermal Shock Events” or 10 CFR 50.61a, “Alternate Fracture 

Toughness Requirements for Protection Against Pressurized Thermal Shock 

Events,” in accordance with the applicant’s CLB (applicable only to pressurized 

water reactor (PWR) plants) 

(d) 10 CFR 50.62, “Requirements for Reduction of Risk from Anticipated Transients 

without Scram Events for Light-Water-Cooled Nuclear Power Plants” 

 (e) 10 CFR 50.63, “Loss of All Alternating Current Power” (applicable to PWR plants) 
2.1-4 

Other NRC staff members may be reviewing the applicant’s scoping and screening results 

separately following the guidance in Sections 2.2 through 2.5. The reviewer should keep these 

other NRC staff members informed of findings that may affect their review of the applicant’s 

scoping and screening results. The reviewer should coordinate this sharing of information through 

the SLR project manager. 

2.1.3.1 Scoping 

Once the information delineated above has been gathered, the NRC staff reviews the applicant’s 

methodology to determine whether its depth and breadth are sufficiently comprehensive to 

identify the SSCs within the scope of SLR, and the SCs requiring an AMR. Because “[t]he CLB 

represents the evolving set of requirements and commitments for a specific plant that are modified 

as necessary over the life of a plant to ensure continuation of an adequate level of safety” 

(60 FR 22465, May 8, 1995), the regulations, orders, license conditions, exemptions, and 

technical specifications (TS) defining functional requirements for facility SSCs that make up an 

applicant’s CLB should be considered as the initial input into the scoping process. DBEs are 

defined in 10 CFR 50.49 as conditions of normal operation, including anticipated operational 

occurrences and design basis accidents (DBAs). DBAs, external events, and natural phenomena 

for which the plant must be designed to ensure: (1) the integrity of the reactor pressure boundary, 

(2) the capability to shut down the reactor and maintain it in 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), 50.67(b)(2), or 100.11, as 

applicable. Therefore, to determine the safety-related SSCs that are within the scope of the Rule 

under 10 CFR 54.4(a)(1), the applicant must identify those SSCs that are relied upon to remain 

functional during and following these DBEs, consistent with the CLB of the facility. Most licensees 

have developed lists or databases that identify SSCs relied on for compliance with other 

regulations in a manner consistent with the CLB of their facilities. Consistent with the licensing 

process and regulatory criteria used to develop such lists or databases, licensees should build 

upon these information sources to satisfy 10 CFR Part 54 requirements. 

With respect to TS, the NRC has stated (60 FR 22467): 

The Commission believes that there is sufficient experience with its policy on technical 

specifications to apply that policy generically in revising the license renewal rule 

consistent with the Commission’s desire to credit existing regulatory programs. 

Therefore, the Commission concludes that the technical specification limiting 

conditions for operation scoping category is unwarranted and has deleted the 

requirement that identifies systems, structures, and components with operability 

requirements in technical specifications as being within the scope of the license 

renewal review. 

Therefore, the applicant need not consider its TS and applicable limiting conditions of operation 

when scoping for SLR. This is not to say that the events and functions addressed within the 

applicant’s TS can be excluded in determining the SSCs within the scope of SLR solely on the 

basis of such an event’s inclusion in the TS. Rather, those SSCs governed by an applicant’s TS 

that are relied upon to remain functional during a DBE, as identified within the applicant’s UFSAR, 

applicable NRC regulations, license conditions, NRC orders, and exemptions, need to be included 

within the scope of SLR. 

For licensee commitments, such as licensee responses to NRC Bulletins, GLs, or enforcement 

actions, and those documented in NRC staff safety evaluations or licensee event reports, and 
2.1-5 

which make up the remainder of an applicant’s CLB, many of the associated SSCs need not be 

considered under SLR. Generic communications, safety evaluations, and other similar 

documents found on the docket are not regulatory requirements, and commitments made by a 

licensee to address any associated safety concerns are not typically considered to be design 

requirements. However, any generic communication, safety evaluation, or licensee commitment 

that specifically identifies or describes a function associated with a SSC necessary to fulfill the 

requirement of a particular regulation, order, license condition, and/or exemption may need to be 

considered when scoping for SLR. For example, NRC Bulletin 88-11, “Pressurizer Surge Line 

Thermal Stratification,” (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML031220290) states: 

The licensing basis according to 10 CFR 50.55a for all PWRs requires that the 

licensee meet the American Society of Mechanical Engineers Boiler and 

Pressure Vessel Code (ASME Code) Sections III and XI and to reconcile the pipe 

stresses and fatigue evaluation when any significant differences are observed 

between measured data and the analytical results for the hypothesized 

conditions. Staff evaluation indicates that the thermal stratification phenomenon 

could occur in all PWR surge lines and may invalidate the analyses supporting 

the integrity of the surge line. The staff’s concerns include unexpected bending 

and thermal striping (rapid oscillation of the thermal boundary interface along the 

piping inside surface) as they affect the overall integrity of the surge line for its 

design life (e.g., the increase of fatigue). 

Therefore, this bulletin specifically describes conditions that may affect compliance with the 

requirements associated with 10 CFR 50.55a and functions specifically related to this regulation 

that must be considered in the scoping process for SLR. 

An applicant may take an approach in scoping and screening that combines similar components 

from various systems. For example, containment isolation valves from various systems may be 

identified as a single system for purposes of SLR. 

NRC staff from branches responsible for systems may be requested to assist in reviewing the 

plant design basis and intended function(s), as necessary. 

The reviewer should verify that the applicant’s scoping methods document the actual information 

sources used (for example, those identified in Table 2.1-1). 

2.1.3.1.1 Safety-Related 

The applicant’s methodology is reviewed to ensure that the safety-related SSCs are identified to 

satisfactorily accomplish any of the intended functions identified in 10 CFR 54.4(a)(1). The 

reviewer must ascertain how, and to what extent, the applicant incorporated the information in the 

CLB for the facility in its methodology. Specifically, the reviewer should review the application, as 

well as all other relevant sources of information outlined above, to identify the set of plant-specific 

conditions of normal operation, DBAs, external events, and natural phenomena for which the plant 

must be designed to ensure the following functions: 
2.1-6 

 The integrity of the reactor coolant pressure boundary; 

 The capability to shut down the reactor and maintain it in a safe shutdown condition; or 

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

potential offsite exposure comparable to the guidelines in 10 CFR 50.34(a)(1), 50.67(b)(2), 

or 100.11, as applicable. 

2.1.3.1.2 Nonsafety-Related 

The applicant’s methodology is reviewed to ensure that nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of any of the functions identified in 

10 CFR 54.4(a)(1) are identified as being within the scope of SLR. 

The scoping criterion under 10 CFR 54.4(a)(2), in general, is intended to identify those 

nonsafety-related SSCs that support safety-related functions. More specifically, this scoping 

criterion requires an applicant to identify all nonsafety-related SSCs whose failure could prevent 

satisfactory accomplishment of any of the functions identified under 10 CFR 54.4(a)(1). 

Section III.c(iii) of the SOC (60 FR 22467) clarifies the NRC’s intent for this requirement in the 

following statement: 

The inclusion of nonsafety-related systems, structures, and components whose 

failure could prevent other systems, structures, and components from 

accomplishing a safety function is intended to provide protection against safety 

function failure in cases where the safety-related structure or component is not 

itself impaired by age-related degradation but is vulnerable to failure from the 

failure of another structure or component that may be so impaired. 

In addition, Section III.c(iii) of the SOC provides the following guidance to assist an applicant 

in determining the extent to which failures must be considered when applying this 

scoping criterion: 

[C]onsideration of hypothetical failures that could result from system 

interdependencies that are not part of the CLB and that have not been previously 

experienced is not required. However, for some license renewal applicants, the 

Commission cannot exclude the possibility that hypothetical failures that are part of 

the CLB may require consideration of second-, third-, or fourth-level support 

systems. 

Therefore, to satisfy the scoping criterion under 10 CFR 54.4(a)(2), the applicant must identify 

those nonsafety-related SSCs (including certain second-, third-, or fourth-level support systems) 

whose failures are considered in the CLB and could prevent the satisfactory accomplishment of a 

safety-related function identified under 10 CFR 54.4(a)(1). In order to identify such systems, the 

applicant should consider those failures identified in: (1) the documentation that makes up its 

CLB, (2) plant-specific operating experience (OE), and (3) industrywide OE that is specifically 

applicable to its facility. The applicant need not consider hypothetical failures that are not part of 

the CLB, have not been previously experienced, or are not applicable to its facility. 

In part, 10 CFR 54.4(a)(2) requires that the applicant consider all nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of any of the functions identified in 

10 CFR 54.4(a)(1)(i), 10 CFR 54.4(a)(1)(ii), or 10 CFR 54.4(a)(1)(iii) to be within the scope of 
2.1-7 

SLR. By letters dated December 3, 2001, and March 15, 2002, the NRC issued a staff position to 

NEI that provided NRC staff guidance for determining what SSCs meet the 10 CFR 54.4(a)(2) 

criterion. The December 3, 2001, letter, “License Renewal Issue: Scoping of Seismic II/I Piping 

Systems,” provided specific examples of OE that identified pipe failure events [summarized in 

Information Notice (IN) 2001-09, “Main Feedwater System Degradation in Safety-Related ASME 

Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor” (ADAMS Accession 

No. ML011490408)] and the approaches the NRC considers acceptable to determine which piping 

systems should be included in scope based on the 10 CFR 54.4(a)(2) criterion. 

The March 15, 2002, letter, “License Renewal Issue: Guidance on the Identification and 

Treatment of Structures, Systems, and Components Which Meet 10 CFR 54.4(a)(2),” (ADAMS 

Accession No. ML020770026) further described the NRC staff’s recommendations for the 

evaluation of nonpiping SSCs to determine which additional nonsafety-related SSCs are within the 

scope of SLR. The position states that the applicants should not consider hypothetical failures, 

but rather should base their evaluation on the plant’s CLB, engineering judgment and analyses, 

and relevant OE. The paper further describes OE as all documented plant-specific and 

industrywide experience that can be used to determine the plausibility of a failure. Documentation 

would include NRC generic communications and event reports, plant-specific condition 

reports, industry reports such as significant OE reports (SOERs) or INPO Event Reports, and 

engineering evaluations. 

For example, the safety classification of a pipe at certain locations, such as valves, may change 

throughout its length in the plant. In these instances, the applicant should identify the 

safety-related portion of the pipe as being within the scope of SLR under 10 CFR 54.4(a)(1). 

However, the entire pipe run, including associated piping anchors, may have been analyzed as 

part of the CLB to establish that it could withstand DBE loads. If this is the case, a failure in the 

pipe run or in the associated piping anchors could render the safety-related portion of the piping 

unable to perform its intended function under CLB design conditions. Therefore, the reviewer 

must verify that the applicant’s methodology would include (1) the remaining nonsafety-related 

piping up to its anchors and (2) the associated piping anchors as being within the scope of SLR 

under 10 CFR 54.4(a)(2). 

In order to comply, in part, with the requirements of 10 CFR 54.4(a)(2), all applicants must include 

in scope all nonsafety-related piping attached directly to safety-related piping (within the scope of 

SLR) up to a defined anchor point consistent with the plant CLB. This anchor point may be 

served by a true anchor (a device or structure that ensures forces and moments are restrained in 

three (3) orthogonal directions) or an equivalent anchor, such as a large piece of plant equipment 

(e.g., a heat exchanger), determined by an evaluation of the plant-specific piping design 

(i.e., design documentation, such as piping stress analysis for the facility). Applicants should be 

able to define an equivalent anchor consistent with their CLB (e.g., described in the UFSAR or 

other CLB documentation), which is being credited for the 10 CFR 54.4(a)(2) evaluation, and be 

able to describe the SCs that are part of the nonsafety-related piping segment boundary up to and 

including the anchor point or equivalent anchor point within the scope of SLR. 

There may be isolated cases where an equivalent anchor point for a particular piping segment is 

not clearly described within the existing CLB information. In those instances, the applicant may 

use a combination of restraints or supports such that the nonsafety-related piping and associated 

SCs attached to safety-related piping is included in scope up to a boundary point that 

encompasses at least two (2) supports in each of three (3) orthogonal directions. 
2.1-8 

It is important to note that the scoping criterion under 10 CFR 54.4(a)(2) specifically applies to 

those functions “identified in paragraphs (a)(1)(i), (ii), and (iii)” of 10 CFR 54.4 and does not apply 

to functions identified in 10 CFR 54.4(a)(3), as discussed below. 

2.1.3.1.3 “Regulated Events” 

The applicant’s methodology is reviewed to ensure that SSCs relied on in safety analyses or plant 

evaluations to perform functions that demonstrate compliance with the requirements of the fire 

protection (FP), environmental qualification (EQ), pressurized thermal shock (PTS) (applicable 

only to PWRs), anticipated transients without scram (ATWS), and station blackout (SBO) 

regulations are identified. The reviewer should review the applicant’s docketed correspondence 

associated with compliance of the facility with these regulations. 

The scoping criteria in 10 CFR 54.4(a)(3) require an applicant to consider “all systems, structures, 

and components relied on in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the Commission's regulations for [FP, EQ, PTS, ATWS and SBO].” 

In addition, Section III.c(iii) (60 FR 22467) of the SOC states that the NRC intended to limit the 

potential for unnecessary expansion of the review for SSCs that meet the scoping criteria under 

10 CFR 54.4(a)(3) and provides additional guidance that qualifies what is meant by “those SSCs 

relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission regulations” in the following statement: 

[T]he Commission intends this nonsafety-related category [§ 54.4(a)(2)] to apply to 

systems, structures, and components whose failure would prevent the 

accomplishment of an intended function of a safety-related system, structure, and 

component. An applicant for license renewal should rely on the plant’s CLB, actual 

plant-specific experience, industry-wide operating experience, as appropriate, and 

existing engineering evaluations to determine those nonsafety-related systems, 

structures, and components that are the initial focus of the license renewal review. 

Therefore, all SSCs that are relied upon in the plant’s CLB (as defined in 10 CFR 54.3), 

plant-specific experience, industrywide experience (as appropriate), and safety analyses or plant 

evaluations to perform a function that demonstrates compliance with NRC regulations identified 

under 10 CFR 54.4(a)(3) are required to be included within the scope of the Rule. For example, if 

a nonsafety-related diesel generator is required for safe shutdown under the fire protection plan, 

the diesel generator and all SSCs specifically relied upon for that generator to comply with NRC 

regulations shall be included within the scope of SLR under 10 CFR 54.4(a)(3). Such SSCs may 

include, but should not be limited to, the cooling water system or systems relied upon for 

operability, the diesel support pedestal, and any applicable power supply cable specifically relied 

upon for safe shutdown in the event of a fire. 

In addition, the last sentence of the second paragraph in Section III.c(iii) of the SOC 

provides the following guidance for limiting the application of the scoping criterion under 

10 CFR 54.4(a)(3) as it applies to the use of hypothetical failures: Consideration of hypothetical 

failures that could result from system interdependencies, that are not part of the current licensing 

bases and that have not been previously experienced is not required. (60 FR 22467) 

The SOC does not provide any additional guidance relating to the use of hypothetical failures 

or the need to consider second-, third-, or fourth-level support systems for scoping under 

10 CFR 54.4(a)(3). Therefore, in the absence of any guidance, an applicant need not consider 

hypothetical failures or second-, third-, or fourth-level support systems in determining the SSCs 
2.1-9 

within the scope of the Rule under 10 CFR 54.4(a)(3). For example, if a nonsafety-related diesel 

generator is relied upon only to remain functional to demonstrate compliance with the NRC SBO 

regulation, the applicant need not consider the following SSCs: (1) an alternate/backup cooling 

water system, (2) nonseismically-qualified building walls, or (3) an overhead segment of 

nonseismically-qualified piping (in a Seismic II/I configuration). This guidance is not intended to 

exclude any support system (whether identified by an applicant’s CLB, or as indicated from actual 

plant-specific experience, industrywide experience (as applicable), safety analyses, or plant 

evaluations) that is specifically relied upon for compliance with the applicable NRC regulation. For 

example, if analysis of a nonsafety-related diesel generator (relied upon to demonstrate 

compliance with an applicable NRC regulation) specifically relies upon a second cooling system to 

cool the diesel generator jacket water cooling system for the generator to be operable, then both 

cooling systems must be included within the scope of the Rule under 10 CFR 54.4(a)(3). 

The applicant is required to identify the SSCs whose functions are relied upon to demonstrate 

compliance with the regulations identified in 10 CFR 54.4(a)(3) (that is, whose functions were 

credited in the analysis or evaluation). Mere mention of an SSC in the analysis or evaluation does 

not necessarily constitute support of an intended function as required by the regulation. 

For environmental qualification, the reviewer verifies that the applicant has indicated that the 

environmental qualification equipment is the equipment already identified by the licensee under 

10 CFR 50.49(b), that is, equipment relied upon in safety analyses or plant evaluations to 

demonstrate compliance with NRC regulations for environmental qualification (10 CFR 50.49). 

For SBO, the reviewer verifies that the applicant’s methodology would include those SSCs relied 

upon during the “coping duration” and “recovery” phase of an SBO event. In addition, because 

10 CFR 50.63(c)(1)(ii) and its associated guidance in RG 1.155 include procedures to recover 

from an SBO that include offsite and onsite power, the offsite power system that is used to 

connect the plant to the offsite power source should also be included within the scope of the Rule. 

However, the NRC staff’s review is based on the plant-specific CLB, regulatory requirements, and 

offsite power design configurations. 

Table 2.2-1 contains examples of system and structure scoping results and the basis for 

the disposition. 

2.1.3.2 Screening 

Once the SSCs within the scope of SLR have been identified, the next step is determining which 

SCs are subject to an AMR (i.e., “screening”). Table 2.1-3 contains specific NRC staff guidance 

on certain subjects of screening. 

2.1.3.2.1 “Passive” 

The reviewer reviews the applicant’s methodology to ensure that “passive” SCs are identified as 

those that perform their intended functions without moving parts or a change in configuration or 

properties in accordance with 10 CFR 54.21(a)(1)(i). The description of “passive” may also be 

interpreted to include SCs that do not display “a change in state.” 10 CFR 54.21(a)(1)(i) provides 

specific examples of SCs that do or do not meet the criterion. The reviewer verifies that the 

applicant’s screening methodology includes consideration of the intended functions of SCs 

consistent with the plant’s CLB, as typified in Tables 2.1-4 and 2.1-5, respectively. 
2.1-10 

The License Renewal Rule focuses on “passive” SCs because SCs that have passive functions 

generally do not have performance and condition characteristics that are as readily observable as 

those that perform active functions. “Passive” SCs, for the purpose of the License Renewal Rule, 

are those that perform an intended function, as described in 10 CFR 54.4, without moving parts or 

without a change in configuration or properties. The description of “passive” may also be 

interpreted to include SCs that do not display “a change of state.” 

Table 2.1-6 provides a list of typical SCs identifying whether they meet 10 CFR 54.21(a)(1)(i). 

10 CFR 54.21(a)(1)(i) explicitly excludes instrumentation, such as pressure transmitters, pressure 

indicators, and water level indicators, from an AMR. The applicant does not have to identify 

pressure-retaining boundaries of this instrumentation because 10 CFR 54.21(a)(1)(i) excludes this 

instrumentation without exception, unlike pumps and valves. Further, instrumentation is sensitive 

equipment and degradation of its pressure retaining boundary would be readily determinable by 

surveillance and testing. If an applicant determines that certain SCs listed in Table 2.1-6 as 

meeting 10 CFR 54.21(a)(1)(i) do not meet that requirement for its plant, the reviewer reviews the 

applicant’s basis for that determination. 

2.1.3.2.2 “Long-Lived” 

The applicant’s methodology is reviewed to ensure that “long-lived” SCs are identified as those 

that are not subject to periodic replacement based on a qualified life or specified time period. 

Passive SCs that are not replaced on the basis of a qualified life or specified time period require 

an AMR. 

Replacement programs may be based on vendor recommendations, plant experience, or any 

means that establishes a specific replacement frequency under a controlled program. 

Section f(i)(b) of the SOC provides the following guidance for identifying “long-lived” SCs: 

In sum, a structure or component that is not replaced either (i) on a specified 

interval based upon the qualified life of the structure or component or 

(ii) periodically in accordance with a specified time period, is deemed by 

§ 54.21(a)(1)(ii) of this rule to be “long-lived,” and therefore subject to the 

§ 54.21(a)(3) aging management review [60 FR 22478]. 

A qualified life does not necessarily have to be based on calendar time. A qualified life based on 

run time or cycles are examples of qualified life references that are not based on calendar time. 

SCs that are replaced on the basis of performance or condition are not generically excluded from 

an AMR. Rather, performance or condition monitoring may be evaluated later in the IPA as 

programs to ensure functionality during the subsequent period of extended operation. On this 

topic, Section f(i)(b) of the SOC provides the following guidance: 

It is important to note, however, that the Commission has decided not to 

generically exclude passive structures and components that are replaced based 

on performance or condition from an aging management review. Absent the 

specific nature of the performance or condition replacement criteria and the fact 

that the Commission has determined that the components with “passive” 

functions are not as readily monitorable as components with active functions, 

such generic exclusion is not appropriate. However, the Commission does not 

intend to preclude a license renewal applicant from providing site-specific 

justification in a license renewal application that a replacement program on the 
2.1-11 

basis of performance or condition for a passive structure or component provides 

reasonable assurance that the intended function of the passive structure or 

component will be maintained in the period of extended operation. 

[60 FR 22478] 

2.1.4 Evaluation Findings 

When the review of the information in the SLR application is complete, and the reviewer 

has determined that it is satisfactory and in accordance with the acceptance criteria in 

Subsection 2.1.2, a statement of the following type should be included in the NRC staff’s safety 

evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

there is reasonable assurance that the applicant’s methodology for identifying the 

systems, structures, and components within the scope of subsequent license 

renewal and the SCs requiring an AMR is consistent with the requirements of 

10 CFR 54.4 and 10 CFR 54.21(a)(1). 

2.1.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

2.1.6 References 

1. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. Agencywide Documents 

Access and Management System (ADAMS) Accession No. ML051860406. 

Washington, DC: Nuclear Energy Institute. June 2005. 

2. NRC. Regulatory Guide 1.29, “Seismic Design Classification for Nuclear Power Plants.” 

Revision 5. ADAMS Accession No. ML16118A148. Washington, DC: U.S. Nuclear 

Regulatory Commission. July 2016. 

3. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants.” ADAMS Accession No. ML070630046. Washington, DC: 

U.S. Nuclear Regulatory Commission. March 2007. 

4. NRC. Generic Letter (GL) 88-20, “Individual Plant Examination for Severe Accident 

Vulnerabilities-10 CFR 50.54(f).” ADAMS Accession No. ML031150465. 

Washington, DC: U.S. Nuclear Regulatory Commission. November 1988. 

5. NRC. Regulatory Guide 1.188, “Standard Format and Content for Applications to 

Renew Nuclear Power Plant Operating Licenses.” Revision 1. ADAMS Accession 

No. ML051920430. Washington, DC: U.S. Nuclear Regulatory Commission. 

September 2005. 
2.1-12 

6. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 0. ADAMS Accession 

No. ML031600708. Washington, DC: Nuclear Energy Institute. March 1996. 
2.1-13 

Table 2.1-1 Sample Listing of Potential Information Sources 

Verified databases (databases that are subject to administrative controls to assure and 

maintain the integrity of the stored data or information) 

Master equipment lists (including NSSS vendor listings) 

Q-lists 

Updated Final Safety Analysis Reports 

Piping and instrument diagrams 

NRC Orders, exemptions, or license conditions for the facility 

Design-basis documents 

General arrangement or structural outline drawings 

Probabilistic risk assessment summary report 

Maintenance rule compliance documentation 

Design-basis event evaluations (including plant-specific 10 CFR 50.59 evaluation procedures) 

Emergency operating procedures 

Docketed correspondence 

System interaction commitments 

Technical specifications 

Environmental qualification program documents 

Regulatory compliance reports (including Safety Evaluation Reports) 

Severe Accident Management Guidelines 

 
2.1-14 

Table 2.1-2 Specific Staff Guidance on Scoping 

Issue Guidance

Commodity 

groups 

The applicant may also group like SCs into commodity groups. Examples of 

commodity groups are pipe supports and cable trays. The basis for grouping 

SCs can be determined by such characteristics as similar function, similar 

design, similar materials of construction, similar aging management practices, 

or similar environments. If the applicant uses commodity groups, the reviewer 

verifies that the applicant has described the basis for the groups. 

Complex 

assemblies 

Some SCs, when combined, are considered a complex assembly (for example, 

diesel generator starting air skids or heating, ventilating, and air conditioning 

refrigerant units). For purposes of performing an AMR, it is important to clearly 

establish the boundaries of review. An applicant should establish the 

boundaries for such assemblies by identifying each structure and component 

that make up the complex assembly and determining whether or not each 

structure and component is subject to an AMR (Ref. 1). 

NEI 95-10, Revision 0, Appendix C, Example 5 (Ref. 6), illustrates how the 

evaluation boundary for a control room chiller complex assembly might be 

determined. The control room chillers were purchased as skid-mounted 

equipment. These chillers are part of the control room chilled water system. 

There are two (2) control room chillers. Each is a 100% capacity refrigeration 

unit. The functions of the control room chillers are to provide a reliable source 

of chilled water at a maximum temperature of 7 °

C (44 °F), to provide a 

pressure boundary for the control room chilled water system, to provide a 

pressure boundary for the service water system, and to provide a pressure 

boundary for the refrigerant. All of these functions are considered intended 

functions. Typically, control room chillers are considered as one functional 

unit; however, for purposes of evaluating the effects of aging, it is necessary to 

consider the individual components. Therefore, the boundary of each control 

room chiller is established as follows: 

1. At the inlet and outlet flanges of the service water system connections on 

the control room chiller condenser. Connected piping is part of the 

service water system. 

2. At the inlet and outlet flanges of the control room chilled water system 

piping connections on the control room chiller evaporator. Connected 

piping is part of the control room chilled water system. 

3. For electrical power supplies, the boundary is the output terminals on the 

circuit breakers supplying power to the skid. This includes the cables 

from the circuit breaker to the skid and applies for 480 VAC and 

120 VAC. 

4. The interface for instrument air supplies is at the instrument air tubing 

connection to the pressure control regulators, temperature controllers and 

transmitters, and solenoid valves located on the skid. The tubing from 
2.1-15 

Table 2.1-2 Specific Staff Guidance on Scoping 

Issue Guidance

the instrument air header to the device on the skid is part of the 

instrument air system. 

5. The interface with the annunciator system is at the external connection of 

the contacts of the device on the skid (limit switch, pressure switch, level 

switch, etc.) that indicates the alarm condition. The cables are part of the 

annunciator system. 

Based on the boundary established, the following components would be 

subject to an AMR: condenser, evaporator, economizer, chiller refrigerant 

piping, refrigerant expansion orifice, foundations and bolting, electrical 

cabinets, cables, conduit, trays and supports, valves. 

Hypothetical 

failures 

For 10 CFR 54.4(a)(2), an applicant should consider those failures identified in: 

(1) the documentation that makes up its CLB, (2) plant-specific OE, and 

(3) industrywide OE that is specifically applicable to its facility. The applicant 

need not consider hypothetical failures that are not part of CLB and that have 

not been previously experienced. 

For example, an applicant should consider including: (1) the portion of a fire 

protection system identified in the UFSAR that supplies water to the refueling 

floor that is relied upon in a DBA analysis as an alternate source of cooling 

water that can be used to mitigate the consequences from the loss of spent 

fuel pool cooling, (2) a nonsafety-related, non-seismically-qualified building 

whose intended function as described in the plant’s CLB is to protect a tank 

that is relied upon as an alternate source of cooling water needed to mitigate 

the consequences of a DBE, and (3) a segment of nonsafety-related piping 

identified as a Seismic II/I component in the applicant’s CLB. 

Cascading For 10 CFR 54.4(a)(3), an applicant need not consider hypothetical failures 

or second-, third-, or fourth-level support systems. For example, if a 

nonsafety-related diesel generator is only relied upon to remain functional to 

demonstrate compliance with the NRC’s SBO regulations, an applicant may 

not need to consider: (1) an alternate/backup cooling water system, (2) the 

diesel generator non-seismically-qualified building walls, or (3) an overhead 

segment of non-seismically-qualified piping (in a Seismic II/I configuration). An 

applicant may not exclude any support system (identified by its CLB, actual 

plant-specific experience, industrywide experience, as applicable, or existing 

engineering evaluations) that is specifically relied upon for compliance with, or 

operation within, applicable NRC regulation. For example, if the analysis of a 

nonsafety-related diesel generator (relied upon to demonstrate compliance 

with an applicable NRC regulation) specifically relies upon a second cooling 

system to cool the diesel generator jacket water cooling system for the diesel 

to be operable, then both cooling systems must be included within the scope of 

the Rule. 

 
2.1-16 

Table 2.1-3 Specific Staff Guidance on Screening 

Issue Guidance 

Consumables Consumables may be divided into the following four categories for the purpose 

of license renewal: (1) packing, gaskets, component seals, and O-rings; 

(2) structural sealants; (3) oil, grease, and component filters; and (4) system 

filters, fire extinguishers, fire hoses, and air packs. The consumables in both 

categories (1) and (2) are considered as subcomponents and are not explicitly 

called out in the scoping and screening procedures. Rather, they are implicitly 

included at the component level (e.g., if a valve is identified as being in scope, 

a seal in that valve would also be in scope as a subcomponent of that valve). 

For category (1), the applicant would generally be able to exclude these 

subcomponents using a clear basis. For category (2), these subcomponents 

may perform functions without moving parts or a change in configuration, and 

they are not typically replaced. The applicant’s structural AMP should address 

these items with respect to an AMR program on a plant-specific basis. The 

consumables in category (3) are usually short-lived and periodically replaced, 

and can normally be excluded from an AMR on that basis. Likewise, the 

consumables that fall within category (4) are typically replaced based on 

performance or condition monitoring that identifies whether these components 

are at the end of their qualified lives and may be excluded, on a plant-specific 

basis, from AMR under 10 CFR 54.21(a)(1)(ii). The applicant should identify 

the standards that are relied on for the replacement as part of the methodology 

description (for example, NFPA standards for fire protection equipment). 

Heat 

exchanger 

intended 

functions 

Both the pressure boundary and heat transfer functions for heat exchangers 

should be considered because heat transfer may be a primary safety function 

of these components. There may be a unique aging effect associated with 

different materials in the heat exchanger parts that are associated with the heat 

transfer function and not the pressure boundary function. Normally the 

programs that effectively manage aging effects of the pressure boundary 

function can, in conjunction with the procedures for monitoring heat exchanger 

performance, effectively manage aging effects applicable to the heat 

transfer function. 

Multiple 

functions 

SCs may have multiple functions. The intended functions as delineated in 

10 CFR 54.4(b) are to be reviewed for SLR. For example, a flow orifice that is 

credited in a plant’s accident analysis to limit flow would have two intended 

functions. One intended function is pressure boundary. The other intended 

function is to limit flow. The reviewer verifies that the applicant has considered 

multiple functions in identifying structure- and component-intended functions. 

 
2.1-17 

Table 2.1-4 Typical “Passive” Structure-Intended Functions 

Structures 

Intended Function Description 

Direct Flow Provide spray shield or curbs for directing flow (e.g., safety 

injection flow to containment sump) 

Expansion/Separation Provide for thermal expansion and/or seismic separation 

Fire Barrier Provide rated fire barrier to confine or retard a fire from 

spreading to or from adjacent areas of the plant 

Flood Barrier Provide flood protection barrier (internal and external 

flooding event) 

Gaseous Release Path Provide path for release of filtered and unfiltered 

gaseous discharge 

Heat Sink Provide heat sink during station blackout or design-basis 

accidents 

HELB Shielding Provide shielding against HELB 

Missile Barrier Provide missile barrier (internally or externally generated) 

Pipe Whip Restraint Provide pipe whip restraint 

Pressure Relief Provide over-pressure protection 

Shelter, Protection Provide shelter/protection to safety-related components 

Shielding Provide shielding against radiation 

Shutdown Cooling Water Provide source of cooling water for plant shutdown 

Structural Pressure Barrier Provide pressure boundary or essentially leak-tight barrier to 

protect public health and safety in the event of any postulated 

design-basis events. 

 
2.1-18 

Table 2.1-5 Typical “Passive” Component-Intended Functions 

Components 

Intended Function Description 

Absorb Neutrons Absorb neutrons 

Electrical Continuity Provide electrical connections to specified sections of an 

electrical circuit to deliver voltage, current, or signals 

Filter Provide filtration 

Heat Transfer Provide heat transfer 

Insulate (electrical) Insulate and support an electrical conductor 

Insulate (thermal) Inhibit/prevent heat transfer across a thermal gradient 

Leakage Boundary (Spatial) Nonsafety-related component that maintains mechanical 

and structural integrity to prevent spatial interactions that 

could cause failure of safety-related SSCs 

Pressure Boundary Provide pressure-retaining boundary so that sufficient flow 

at adequate pressure is delivered, or provide fission 

product barrier for containment pressure boundary, or 

provide containment isolation for fission product retention 

Spray Convert fluid into spray 

Structural Integrity (Attached) Nonsafety-related component that maintains mechanical 

and structural integrity to provide structural support to 

attached safety-related piping and components 

Structural Support Provide structural and/or functional support to 

safety-related and/or nonsafety-related components 

Throttle Provide flow restriction 

 
2.1-19 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

1 Structures Category I Structures Yes 

2 Structures Primary Containment Structure Yes 

3 Structures Intake Structures Yes 

4 Structures Intake Canal Yes 

5 Structures Other Non-Category I Structures 

within the Scope of SLR 

Yes 

6 Structures Equipment Supports and 

Foundations 

Yes 

7 Structures Structural Bellows Yes 

8 Structures Controlled Leakage Doors Yes 

9 Structures Penetration Seals Yes 

10 Structures Compressible Joints and Seals Yes 

11 Structures Fuel Pool and Sump Liners Yes 

12 Structures Concrete Curbs Yes 

13 Structures Offgas Stack and Flue Yes 

14 Structures Fire Barriers Yes 

15 Structures Pipe Whip Restraints and Jet 

Impingement Shields 

Yes 

16 Structures Electrical and Instrumentation 

and Control Penetration 

Assemblies 

Yes 

17 Structures Instrumentation Racks, Frames, 

Panels, and Enclosures 

Yes 

18 Structures Electrical Panels, Racks, 

Cabinets, and Other Enclosures 

Yes 

19 Structures Cable Trays and Supports Yes 

20 Structures Conduit Yes 

21 Structures TubeTrack® Yes 

22 Structures Reactor Vessel Internals Yes 

23 Structures ASME Class 1 Hangers and 

Supports 

Yes 

24 Structures Non-ASME Class 1 Hangers and 

Supports 

Yes 

25 Structures Snubbers No 

26 Reactor Coolant Pressure 

Boundary Components 

(Note: the components of 

the RCPB are defined by 

each plant's CLB and 

site-specific 

documentation) 

ASME Class 1 Piping Yes 

27 Reactor Coolant Pressure 

Boundary Components 

Reactor Vessel Yes 
2.1-20 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

28 Reactor Coolant Pressure 

Boundary Components 

Reactor Coolant Pumps Yes (Casing) 

29 Reactor Coolant Pressure 

Boundary Components 

Control Rod Drives No 

30 Reactor Coolant Pressure 

Boundary Components 

Control Rod Drive Housing Yes 

31 Reactor Coolant Pressure 

Boundary Components 

Steam Generators Yes 

32 Reactor Coolant Pressure 

Boundary Components 

Pressurizer Yes 

33 Non-Class 1 Piping 

Components 

Underground Piping Yes 

34 Non-Class 1Piping 

Components 

Piping in Low Temperature 

Demineralized Water Service 

Yes 

35 Non-Class 1 Piping 

Components 

Piping in High Temperature 

Single Phase Service 

Yes 

36 Non-Class 1 Piping 

Components 

Piping in Multiple Phase Service Yes 

37 Non-Class 1 Piping 

Components 

Service Water Piping Yes 

38 Non-Class 1 Piping 

Components 

Low Temperature Gas Transport 

Piping 

Yes 

39 Non-Class 1 Piping 

Components 

Stainless Steel Tubing Yes 

40 Non-Class 1 Piping 

Components 

Instrument Tubing Yes 

41 Non-Class 1 Piping 

Components 

Expansion Joints Yes 

42 Non-Class 1 Piping 

Components 

Ductwork Yes 

43 Non-Class 1 Piping 

Components 

Sprinkler Heads Yes 

44 Non-Class 1 Piping 

Components 

Miscellaneous Appurtenances 

(Includes fittings, couplings, 

reducers, elbows, thermowells, 

flanges, fasteners, welded 

attachments, etc.) 

Yes 

45 Pumps ECCS Pumps Yes (Casing) 

46 Pumps Service Water and Fire Pumps Yes (Casing) 

47 Pumps Lube Oil and Closed Cooling 

Water Pumps 

Yes (Casing) 

48 Pumps Condensate Pumps Yes (Casing) 

49 Pumps Borated Water Pumps Yes (Casing) 
2.1-21 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

50 Pumps Emergency Service Water 

Pumps 

Yes (Casing) 

51 Pumps Submersible Pumps Yes (Casing) 

52 Turbines Turbine Pump Drives 

(excluding pumps) 

Yes (Casing) 

53 Turbines Gas Turbines Yes (Casing) 

54 Turbines Controls (Actuator and 

Overspeed Trip) 

No 

55 Engines Fire Pump Diesel Engines No 

56 Emergency Diesel 

Generators 

Emergency Diesel Generators No 

57 Heat Exchangers Condensers Yes 

58 Heat Exchangers Heating, ventilation, and air 

conditioning (HVAC) Coolers 

(including housings) 

Yes 

59 Heat Exchangers Primary Water System Heat 

Exchangers 

Yes 

60 Heat Exchangers Treated Water System Heat 

Exchangers 

Yes 

61 Heat Exchangers Closed Cooling Water System 

Heat Exchangers 

Yes 

62 Heat Exchangers Lubricating Oil System Heat 

Exchangers 

Yes 

63 Heat Exchangers Raw Water System Heat 

Exchangers 

Yes 

64 Heat Exchangers Containment Atmospheric 

System Heat Exchangers 

Yes 

65 Miscellaneous Process 

Components 

Gland Seal Blower No 

66 Miscellaneous Process 

Components 

Recombiners The applicant shall 

identify the intended 

function and apply the 

IPA process to determine 

if the grouping is active 

or passive. 

67 Miscellaneous Process 

Components 

Flexible Connectors Yes 

68 Miscellaneous Process 

Components 

Strainers Yes 

69 Miscellaneous Process 

Components 

Rupture Disks Yes 

70 Miscellaneous Process 

Components 

Steam Traps Yes 
2.1-22 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

71 Miscellaneous Process 

Components 

Restricting Orifices Yes 

72 Miscellaneous Process 

Components 

Air Compressor No 

73 Electrical and 

instrumentation and control 

Alarm Unit (e.g., fire detection 

devices) 

No 

74 Electrical and I&C Analyzers (e.g., gas analyzers, 

conductivity analyzers) 

No 

75 Electrical and I&C Annunciators (e.g., lights, 

buzzers, alarms) 

No 

76 Electrical and I&C Batteries No 

77 Electrical and I&C Cables and Connections, Bus, 

electrical portions of Electrical 

and I&C Penetration Assemblies, 

includes fuse holders outside of 

cabinets of active electrical SCs 

(e.g., electrical penetration 

assembly cables and 

connections, connectors, 

electrical splices, fuse holders, 

terminal blocks, power cables, 

control cables, instrument cables, 

insulated cables, communication 

cables, uninsulated ground 

conductors, transmission 

conductors, isolated-phase bus, 

non-segregated-phase bus, 

segregated-phase bus, 

switchyard bus) 

Yes 

78 Electrical and I&C Chargers, Converters, Inverters 

(e.g., converters-voltage/current, 

converters-voltage/pneumatic, 

battery chargers/inverters, 

motor-generator sets) 

No 

79 Electrical and I&C Circuit Breakers (e.g., air circuit 

breakers, molded case circuit 

breakers, oil-filled circuit 

breakers) 

No 
2.1-23 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

80 Electrical and I&C Communication Equipment 

(e.g., telephones, video or audio 

recording or playback equipment, 

intercoms, computer terminals, 

electronic messaging, radios, 

transmission line traps, and other 

power-line carrier equipment) 

No 

81 Electrical and I&C Electric Heaters No 

Yes, for a Pressure 

Boundary if applicable 

82 Electrical and I&C Heat Tracing No 

83 Electrical and I&C Electrical Controls and Panel 

Internal Component Assemblies 

(may include internal devices 

such as, but not limited to, 

switches, breakers, indicating 

lights, etc.) (e.g., main control 

board, HVAC control board) 

No 

84 Electrical and I&C Elements, RTDs, Sensors, 

Thermocouples, Transducers 

(e.g., conductivity elements, flow 

elements, temperature sensors, 

radiation sensors, watt 

transducers, thermocouples, 

RTDs, vibration probes, amp 

transducers, frequency 

transducers, power factor 

transducers, speed transducers, 

var. transducers, vibration 

transducers, voltage transducers)

No 

Yes for a pressure 

boundary if applicable 

85 Electrical and I&C Fuses No 

86 Electrical and I&C Generators, Motors 

(e.g., emergency diesel 

generators, ECCS and 

emergency service water pump 

motors, small motors, motorgenerator sets, steam turbine 

generators, combustion turbine 

generators, fan motors, pump 

motors, valve motors, air 

compressor motors) 

No 
2.1-24 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

87 Electrical and I&C High-Voltage Insulators 

(e.g., porcelain switchyard 

insulators, transmission line 

insulators) 

Yes 

88 Electrical and I&C Surge Arresters (e.g., switchyard 

surge arresters, lightning 

arresters, surge suppressers, 

surge capacitors, protective 

capacitors) 

No 

89 Electrical and I&C Indicators (e.g., differential 

pressure indicators, pressure 

indicators, flow indicators, level 

indicators, speed indicators, 

temperature indicators, analog 

indicators, digital indicators, LED 

bar graph indicators, 

LCD indicators) 

No 

90 Electrical and I&C Isolators (e.g., transformer 

isolators, optical isolators, 

isolation relays, isolating transfer 

diodes) 

No 

91 Electrical and I&C Light Bulbs (e.g., indicating lights, 

emergency lighting, incandescent 

light bulbs, fluorescent 

light bulbs) 

No 

92 Electrical and I&C Loop Controllers (e.g., differential 

pressure indicating controllers, 

flow indicating controllers, 

temperature controllers, 

controllers, speed controllers, 

programmable logic controller, 

single loop digital controller, 

process controllers, manual 

loader, selector station, 

hand/auto station, auto/manual 

station) 

No 

93 Electrical and I&C Meters (e.g., ammeters, volt 

meters, frequency meters, var 

meters, watt meters, power factor 

meters, watt-hour meters) 

No 

94 Electrical and I&C Power Supplies No 
2.1-25 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

95 Electrical and I&C Radiation Monitors (e.g., area 

radiation monitors, process 

radiation monitors) 

No 

96 Electrical and I&C Recorders (e.g., chart recorders, 

digital recorders, events 

recorders) 

No 

97 Electrical and I&C Regulators (e.g., voltage 

regulators) 

No 

98 Electrical and I&C Relays (e.g., protective relays, 

control/logic relays, auxiliary 

relays) 

No 

99 Electrical and I&C Signal Conditioners No 

100 Electrical and I&C Solenoid Operators No 

101 Electrical and I&C Solid-State Devices 

(e.g., transistors, circuit boards, 

computers) 

No 

102 Electrical and I&C Switches (e.g., differential 

pressure indicating switches, 

differential pressure switches, 

pressure indicator switches, 

pressure switches, flow switches, 

conductivity switches, 

level-indicating switches, 

temperature-indicating switches, 

temperature switches, moisture 

switches, position switches, 

vibration switches, level switches, 

control switches, automatic 

transfer switches, manual 

transfer switches, manual 

disconnect switches, current 

switches, limit switches, 

knife switches) 

No 
2.1-26 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

103 Electrical and I&C Switchgear, Load Centers, Motor 

Control Centers, Distribution 

Panel Internal Component 

Assemblies (may include internal 

devices such as, but not limited 

to, switches, breakers, indicating 

lights, etc.) (e.g., 4.16 kV 

switchgear, 480V load centers, 

480V motor control centers, 

250 VDC motor control centers, 

6.9 kV switchgear units, 

240/125V power distribution 

panels) 

No 

104 Electrical and I&C Transformers (e.g., instrument 

transformers, load center 

transformers, small distribution 

transformers, large power 

transformers, isolation 

transformers, coupling capacitor 

voltage transformers) 

No 

105 Electrical and I&C Transmitters (e.g., differential 

pressure transmitters, pressure 

transmitters, flow transmitters, 

level transmitters, radiation 

transmitters, static pressure 

transmitters) 

No 

106 Valves Hydraulic-Operated Valves Yes (Bodies) 

107 Valves Explosive Valves Yes (Bodies) 

108 Valves Manual Valves Yes (Bodies) 

109 Valves Small Valves Yes (Bodies) 

110 Valves Motor-Operated Valves Yes (Bodies) 

111 Valves Air-Operated Valves Yes (Bodies) 

112 Valves Main Steam Isolation Valves Yes (Bodies) 

113 Valves Small Relief Valves Yes (Bodies) 

114 Valves Check Valves Yes (Bodies) 

115 Valves Safety Relief Valves Yes (Bodies) 

116 Valves Dampers, louvers, and gravity 

dampers 

Yes (Housings) 

117 Tanks Air Accumulators Yes 

118 Tanks Discharge Accumulators 

(Dampers) 

Yes 

119 Tanks Boron Acid Storage Tanks Yes 

120 Tanks Above Ground Oil Tanks Yes 
2.1-27 

Table 2.1-6 Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, Component, or 

Commodity Grouping 

Structure, Component, 

or Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

121 Tanks Underground Oil Tanks Yes 

122 Tanks Demineralized Water Tanks Yes 

123 Tanks Neutron Shield Tank Yes 

124 Fans Ventilation Fans (includes intake 

fans, exhaust fans, and purge 

fans) 

Yes (Housings) 

125 Fans Other Fans Yes (Housings) 

126 Miscellaneous Emergency Lighting No 

127 Miscellaneous Hose Stations Yes 

2.2-1 

2.2 Plant-Level Scoping Results 

Review Responsibilities 

Primary—Assigned branch(es) 

Secondary—None 

2.2.1 Areas of Review 

This section addresses the plant-level scoping results for subsequent license renewal (SLR). 

Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires the applicant to identify 

and list structures and components (SCs) subject to an aging management review (AMR). These 

are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 10 CFR 54.21(a)(2) 

requires the applicant to describe and justify the methods used to identify these SCs. The 

U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s methodology separately, 

following the guidance in Section 2.1. 

The applicant should provide a list of all the plant systems and structures, identifying those that 

are within the scope of SLR. If the list exists elsewhere, such as in the updated final safety 

analysis report (UFSAR), it is acceptable to merely identify the reference. The License Renewal 

Rule does not require the identification of all plant systems and structures within the scope of 

SLR. However, providing such a list may make the review more efficient. 

On the basis of the design basis events (DBEs) considered in the plant’s current licensing basis 

(CLB) and other CLB information relating to nonsafety-related systems and structures and certain 

regulated events, the applicant would identify those plant-level systems and structures within the 

scope of SLR, as defined in 10 CFR 54.4(a). This is “scoping” of the plant-level systems and 

structures for SLR. To verify that the applicant has properly implemented its methodology, the 

NRC staff focuses its review on the implementation results to confirm that there is no omission of 

plant-level systems and structures within the scope of SLR. 

Examples of plant systems are the reactor coolant, containment spray, standby gas treatment 

[boiling water reactor (BWR)], emergency core cooling, open and closed cycle cooling water, 

compressed air, chemical and volume control [pressurized water reactor (PWR)], standby liquid 

control (BWR), main steam, feedwater, condensate, steam generator blowdown (PWR), and 

auxiliary feedwater systems (PWR). 

Examples of plant structures are the primary containment, secondary containment (BWR), 

control room, auxiliary building, fuel storage building, radwaste building, and ultimate heat sink 

cooling tower. 

Examples of components are the reactor vessel, reactor vessel internals, steam generator (PWR), 

and light and heavy load-handling cranes. Some applicants may have categorized such 

components as plant “systems” for their convenience. 

After plant-level scoping, the applicant should identify the portions of the system or structure that 

perform an intended function, as defined in 10 CFR 54.4(b). Then the applicant should identify 

those SCs that are “passive” and “long-lived,” in accordance with 10 CFR 54.21(a)(1)(i) and (ii). 

These “passive,” “long-lived” SCs are those that are subject to an AMR. The NRC staff reviews 

these results separately following the guidance in Sections 2.3 through 2.5. 
2.2-2 

The applicant has the flexibility to determine the set of systems and structures it considers as 

within the scope of SLR, provided that this set includes the systems and structures that the NRC 

has determined are within the scope of SLR. Therefore, the reviewer need not review all systems 

and structures that the applicant has identified to be within the scope of SLR because the 

applicant has the option to include more systems and components than those defined to be within 

the scope of SLR by 10 CFR 54.4. 

The following areas relating to the methodology implementation results for the plant-level systems 

and structures are reviewed. 

2.2.1.1 Systems and Structures Within the Scope of Subsequent License Renewal 

The reviewer verifies the applicant’s identification of plant-level systems and structures that are 

within the scope of SLR. 

2.2.2 Acceptance Criteria 

The acceptance criteria for the area of review define methods for determining whether the 

applicant has identified the systems and structures within the scope of SLR in accordance with 

NRC regulations in 10 CFR 54.4. For the applicant’s implementation of its methodology to be 

acceptable, the NRC staff should have reasonable assurance that there has been no omission of 

plant-level systems and structures within the scope of SLR. 

2.2.2.1 Systems and Structures Within the Scope of Subsequent License Renewal 

Systems and structures are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are: 

 Safety-related systems and structures that are relied upon to remain functional during and 

following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the following functions: 

– The integrity of the reactor coolant pressure boundary, 

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

condition, or 

– The capability to prevent or mitigate the consequences of accidents that could 

result in potential offsite exposure comparable to the guidelines in 

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

 All nonsafety-related systems and structures whose failure could prevent satisfactory 

accomplishment of any of the functions identified in 10 CFR 54.4(a)(1) above. 

 All systems and structures relied on in safety analyses or plant evaluations to perform 

a function that demonstrates compliance with NRC 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 

(SBO) (10 CFR 50.63). 
2.2-3 

2.2.3 Review Procedures 

The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

additional information from the applicant regarding why a certain system or structure was not 

identified by the applicant as being within the scope of SLR for the applicant’s plant, the reviewer 

should provide a focused question, clearly explaining what information is needed, explaining why 

it is needed, and how it will allow the NRC staff to make its safety finding. In addition, other NRC 

staff members review the applicant’s scoping and screening methodology separately following the 

guidance in Section 2.1. The reviewer should keep these other NRC staff members informed of 

findings that may affect their review of the applicant’s methodology. The reviewer should 

coordinate this sharing of information through the SLR project manager. 

For the area of review, the following review procedures are to be followed. 

2.2.3.1 Systems and Structures Within the Scope of Subsequent License Renewal 

The reviewer determines whether the applicant has properly identified the plant-level systems and 

structures within the scope of SLR by reviewing selected systems and structures that the 

applicant did not identify as being within the scope of SLR to verify that they do not have any 

intended functions. 

The reviewer should use the plant UFSAR, orders, applicable regulations, exemptions, and 

license conditions to determine the design basis for the systems, structures, and components 

(SSCs) (if components are identified as “systems” by the applicant). The design basis determines 

the intended function(s) of an SSC. Such functions determine whether the SSC is within the 

scope of SLR under 10 CFR 54.4. 

This section addresses scoping at a system or structure level. Thus, if any portion of a system or 

structure performs an intended function as defined in 10 CFR 54.4(b), the system or structure is 

within the scope of SLR. The reviews of individual portions of systems and structures that are 

within the scope of SLR are addressed separately in Sections 2.3 through 2.5. 

The applicant should submit a list of all plant-level systems and structures, identifying those that 

are within the scope of SLR (10 CFR 54.4) and subject to AMR (10 CFR 54.21(a)(1). The 

reviewer should sample selected systems and structures that the applicant did not identify as 

within the scope of SLR to determine if they perform any intended functions. The following are 

examples: 

 The applicant does not identify the radiation monitoring system as being within the scope 

of SLR. The reviewer may review the UFSAR to verify that this particular system does not 

perform any intended functions at the applicant’s plant. 

 The applicant does not identify the polar crane as being within the scope of SLR. The 

reviewer may review the UFSAR to verify that this particular structure is not “Seismic II 

over I,” denoting a structure that is not seismic Category I interacting with a seismic 

Category I structure as described in Position C.2 of Regulatory Guide 1.29, “Seismic 

Design Classification for Nuclear Power Plants” (Ref. 1). 
2.2-4 

 The applicant does not identify the fire protection pump house as within the scope of SLR. 

The reviewer may review the plant’s commitments to the fire protection regulation 

(10 CFR 50.48) to verify that this particular structure does not perform any intended 

functions at the plant. 

 The applicant uses the “spaces” approach for scoping electrical equipment and elects to 

include all electrical equipment onsite to be within the scope of SLR except for the 525 kV 

switchyard and the 230 kV transmission lines. The reviewer may review the UFSAR and 

commitments to the SBO regulation (10 CFR 50.63) to verify that the 525 kV switchyard 

and the 230 kV transmission lines do not perform any intended functions at the 

applicant’s plant. 

The applicant may choose to group similar components and structures together in commodity 

groups for separate analyses. If only a portion of a system or structure has an intended function 

and is addressed separately in a specific commodity group, it is acceptable for an applicant to 

identify that system or structure as not being within the scope of SLR. However, for 

completeness, the applicant should include some reference indicating that the portion of the 

system or structure with an intended function that is evaluated with the commodity group. 

Section 2.1 contains additional guidance on the following: 

 Commodity groups 

 Complex assemblies 

 Hypothetical failure 

 Cascading 

If the reviewer has reviewed systems and structures in sufficient detail and does not identify any 

omissions of systems and structures from those within the scope of SLR, the NRC staff would 

have reasonable assurance that the applicant has identified the systems and structures within the 

scope of SLR. 

If the reviewer determines that the applicant has satisfied the criteria described in this review 

section, the NRC staff would have reasonable assurance that the applicant has identified the 

systems and structures within the scope of SLR. 

2.2.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the Standard Review Plan for Review of Subsequent License Renewal Applications 

for Nuclear Power Plants, then the NRC staff’s evaluation supports conclusions of the following 

type, to be included in the safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

there is reasonable assurance that the applicant has appropriately identified the 

systems and structures within the scope of SLR in accordance with 10 CFR 54.4. 

2.2.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. For a proposed alternative, the staff 
2.2-5 

evaluates the alternative on a case-by-case basis and finds it acceptable if the staff determines 

that the alternative provides reasonable assurance that the component’s intended functions will 

be maintained. 

Table 2.2-1 contains examples of system and structure scoping results and the basis for 

the disposition. 

2.2.6 References 

1. NRC. Regulatory Guide 1.29, “Seismic Design Classification for Nuclear Power Plants.” 

Revision 5. Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML16118A148. Washington, DC: U.S. Nuclear Regulatory Commission. 

July 2016. 
2.2-6 

Table 2.2-1 Examples of System and Structure Scoping and Basis for 

Disposition 

Example Disposition 

Recirculation cooling water 

system 

One function of the recirculation cooling water system is to 

remove decay heat from the stored fuel in the spent fuel 

pool via the spent fuel pool cooling system. However, the 

spent fuel pool cooling system at the subject facility is not 

safety-related, and, following a seismic event, the 

safety-related spent fuel pool structure and spent fuel pool 

makeup water supplies ensure the adequate removal of 

decay heat to prevent potential offsite exposures 

comparable to those described in 10 CFR Part 100. 

Therefore, the recirculation cooling water system is not 

within the scope of SLR based on the spent fuel decay heat 

removal function. 

SBO diesel generator building The plant’s UFSAR indicates that certain structural 

components of the SBO diesel generator building for the 

plant are designed to preclude seismic failure and 

subsequent impact of the structure on the adjacent 

safety-related emergency diesel generator building. In 

addition, the UFSAR indicates that certain equipment 

attached to the roof of the building has been anchored to 

resist tornado wind loads. Thus, the SBO diesel generator 

building is within the scope of SLR. 
2.3-1 

2.3 Scoping and Screening Results: Mechanical Systems 

Review Responsibilities 

Primary—Assigned branch(es) 

Secondary—None 

2.3.1 Areas of Review 

This section addresses the mechanical systems scoping and screening results for subsequent 

license renewal (SLR). Typical mechanical systems consist of the following: 

 Reactor coolant system (such as reactor vessel and internals, components forming part of 

coolant pressure boundary, coolant piping system and connected lines, and 

steam generators). 

 Engineered safety features (such as containment spray and isolation systems, standby 

gas treatment system, emergency core cooling system, and fan cooler system). 

 Auxiliary systems (such as new and spent fuel storage, spent fuel cooling and cleanup 

systems, suppression pool cleanup system, load handling system, open and closed cycle 

cooling water systems, ultimate heat sink, compressed air system, chemical and volume 

control system, standby liquid control system, coolant storage/refueling water systems, 

ventilation systems, diesel generator system, and fire protection system). 

 Steam and power conversion system (such as turbines, main and extraction steam, 

feedwater, condensate, steam generator blowdown, and auxiliary feedwater). 

Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to identify 

and list structures and components (SCs) subject to an aging management review (AMR). These 

are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 10 CFR 54.21(a)(2) 

requires an applicant to describe and justify the methods used to identify these SCs. The 

U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s methodology separately 

following the guidance in Section 2.1. To verify that the applicant has properly implemented its 

methodology, the NRC staff focuses its review on the implementation results. Such a focus 

allows the NRC staff to confirm that there is no omission of mechanical system components that 

are subject to an AMR by the applicant. If the review identifies no omission, the NRC staff has the 

basis to find that there is reasonable assurance that the applicant has identified the mechanical 

system components that are subject to an AMR. 

An applicant should list all plant-level systems and structures. On the basis of the design basis 

events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information

relating to nonsafety-related systems and structures and certain regulated events, the applicant 

should identify those plant-level systems and structures within the scope of SLR, as defined in 

10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. The NRC 

staff reviews the applicant’s plant-level “scoping” results separately following the guidance in 

Section 2.2. 

For a mechanical system that is within the scope of SLR, the applicant should identify the portions 

of the system that perform an intended function, as defined in 10 CFR 54.4(b). The applicant may 
2.3-2 

identify these particular portions of the system in marked-up piping and instrument diagrams 

(P&IDs) or in other media. This is “scoping” of mechanical components in a system to identify 

those that are within the scope of SLR for a system. 

For those identified mechanical components that are within the scope of SLR, the applicant must 

identify those that are “passive” and “long-lived,” as required by 10 CFR 54.21(a)(1)(i) and (ii). 

These “passive,” “long-lived” mechanical components are those that are subject to an AMR. This 

is “screening” of mechanical components in a system to identify those that are “passive” and 

“long-lived.” 

The applicant has the flexibility to determine the set of SCs for which an AMR is performed, 

provided that this set includes the SCs for which the NRC has determined that an AMR is 

required. This is based on the Statements of Consideration for the License Renewal Rule 

(60 FR 22478). Therefore, the reviewer need not review all components that the applicant has 

identified as subject to an AMR because the applicant has the option to include more components 

than those required to be subject to an AMR pursuant to 10 CFR 54.21(a)(1). 

2.3.2 Acceptance Criteria 

The acceptance criteria for the areas of review define methods for determining whether the 

applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the applicant’s 

implementation of its methodology to be acceptable, the NRC staff should have reasonable 

assurance that there has been no omission of mechanical system components that are subject to 

an AMR. 

2.3.2.1 Components Within the Scope of Subsequent License Renewal 

Mechanical components are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are: 

 Safety-related systems, structures, and components (SSCs) that are relied upon to remain 

functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the 

following functions: 

— The integrity of the reactor coolant pressure boundary; 

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

condition; or 

— The capability to prevent or mitigate the consequences of accidents that could 

result in potential offsite exposure comparable to the guidelines in 

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

 All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii). 

 All SSCs relied on in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with NRC 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). 
2.3-3 

2.3.2.2 Components Subject to an Aging Management Review 

Mechanical components are subject to an AMR if they are within the scope of SLR and perform 

an intended function as defined in 10 CFR 54.4(b) without moving parts or a change in 

configuration or properties (“passive”), and are not subject to replacement based on a qualified life 

or specified time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)]. 

2.3.3 Review Procedures 

The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

additional information from the applicant regarding why a certain component was not identified by 

the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, the 

reviewer should provide a focused question that clearly explains what information is needed, why 

the information is needed, and how the information will allow the NRC staff to make its safety 

finding. In addition, other NRC staff members review the applicant’s scoping and screening 

methodology separately, following the guidance in Section 2.1. The reviewer should keep these 

other NRC staff members informed of findings that may affect their review of the applicant’s 

methodology. The reviewer should coordinate this sharing of information through the SLR 

project manager. 

For each area of review, the following review procedures are to be followed. 

2.3.3.1 Components Within the Scope of Subsequent License Renewal 

In this step, the NRC staff determines whether the applicant has properly identified the 

components that are within the scope of SLR. The Rule requires applicants to identify 

components that are within the scope of SLR and subject to an AMR. In the past, license renewal 

applications have included a table of components that are within the scope of SLR; that 

information need not be submitted with subsequent license renewal applications. Although a list 

of within the scope of SLR components will be available at plant sites for inspection, the reviewer 

should determine through sampling of P&IDs, and review of the updated final safety analysis 

report (UFSAR) and other plant documents, what portion of the components are within the scope 

of SLR. The reviewer should check to see if any components exist that the NRC staff believes are 

within the scope of SLR but are not identified by the applicant as being subject to an AMR (and 

request that the applicant provide justification for omitting those components that are “passive” 

and “long-lived”). 

The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

conditions to determine the design basis for the SSCs. The design basis specifies the intended 

function(s) of the system(s). That intended function is used to determine the components within 

that system that are relied upon for the system to perform its intended functions. 

The reviewer should focus the review on those components that are not identified as being within 

the scope of SLR, especially the SLR boundary points and major flow paths. The reviewer should 

verify that the components do not have intended functions. Portions of the system identified as 

being within the scope of SLR by the applicant do not have to be reviewed because the applicant 

has the option to include more components within the scope than the Rule requires. 

Further, the reviewer should select system functions described in the UFSAR that are required by 

10 CFR 54.4 to verify that components having intended functions were not omitted from the scope 

of the Rule. 
2.3-4 

For example, if a reviewer verifies that a portion of a system does not perform an intended 

function, is not identified as being subject to an AMR by the applicant, and is isolated from the 

portion of the system that is identified as being subject to an AMR by a boundary valve, the 

reviewer should verify that the boundary valve is subject to an AMR, or that the valve is not 

necessary for the within-scope portion of the system to perform its intended function. Likewise, 

the reviewer should identify, to the extend practical, the system functions of the piping runs and 

components that are identified as not being within the scope of SLR to ensure they do not have 

intended functions that meet the requirements of 10 CFR 54.4. 

Section 2.1 contains additional guidance on the following: 

 Commodity groups 

 Complex assemblies 

 Hypothetical failure 

 Cascading 

If the reviewer has reviewed components in sufficient detail and does not identify any omissions of 

components within the scope of SLR, the reviewer would have reasonable assurance that the 

applicant has identified the components within the scope of SLR for the mechanical systems. 

Table 2.3-1 provides examples of mechanical components scoping lessons learned from the 

review of the initial license renewal (LR) applications and the basis for their disposition. 

2.3.3.2 Components Subject to an Aging Management Review 

In this step, the reviewer determines whether the applicant has properly identified the components 

subject to an AMR from among those that are within the scope of SLR renewal (i.e., those 

identified in Subsection 2.3.3.1). The reviewer should review selected components that the 

applicant has identified as within the scope of SLR but as not subject to an AMR. The reviewer 

should verify that the applicant has not omitted, from an AMR, components that perform intended 

functions without moving parts or without a change in configuration or properties and that are not 

subject to replacement on the basis of a qualified life or specified time period. 

Starting with the boundary verified in Subsection 2.3.3.1, the reviewer should sample components 

that are within the scope of SLR for that system, but were not identified by the applicant as subject 

to an AMR. Only components that are “passive” and “long-lived” are subject to an AMR. 

Table 2.1-6 is provided for the reviewer to assist in identifying whether certain components are 

“passive.” The applicant should justify omitting a component from an AMR that is within the scope 

of SLR at their facility and is listed as “passive” on Table 2.1-6. Although Table 2.1-6 is extensive, 

it may not be all-inclusive. Thus, the reviewer should use other available information sources, 

such as prior application reviews, to determine whether a component may be subject to an AMR. 

For example, an applicant has marked a boundary of a certain system that is within the scope of 

SLR. The marked-up diagram shows that there are pipes, valves, and air compressors within this 

boundary. The applicant has identified piping and valve bodies as subject to an AMR. Because 

Table 2.1-6 indicates that air compressors are not subject to an AMR, the reviewer should find the 

applicant’s determination acceptable. 
2.3-5 

Section 2.1 contains additional guidance on screening the following: 

 Consumables 

 Heat exchanger-intended functions 

 Multiple functions 

If the reviewer does not identify any omissions of components from those that are subject to an 

AMR, the NRC staff would then have reasonable assurance that the applicant has identified the 

components subject to an AMR for the mechanical systems. 

Table 2.3-2 provides examples of mechanical components screening developed from lessons 

learned during the review of the initial LR applications and bases for their disposition. 

If the applicant determines that a component is subject to an AMR, the applicant should also 

identify the component’s intended function, as defined in 10 CFR 54.4. Such functions must be 

maintained by any necessary AMRs. Table 2.3-3 provides examples of mechanical 

component-intended functions. 

2.3.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the Standard Review Plan for Review of Subsequent License Renewal Applications 

for Nuclear Power Plants, then the NRC staff’s evaluation would support conclusions of the 

following type, to be included in the safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

there is reasonable assurance that the applicant has appropriately identified the 

mechanical system components within the scope of subsequent license renewal, 

as required by 10 CFR 54.4, and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.3.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. For a proposed alternative, the staff 

evaluates the alternative on a case-by-case basis and finds it acceptable if the staff determines 

that the alternative provides reasonable assurance that the component’s intended functions will 

be maintained. 

2.3.6 References 

None 
2.3-6 

Table 2.3-1 Examples of Mechanical Components Scoping and Basis for 

Disposition 

Example Disposition 

Piping segment that provides 

structural support 

The safety-related/nonsafety-related boundary along a pipe 

run may occur at a valve location. The nonsafety-related 

piping segment between this valve and the next seismic 

anchor provides structural support in a seismic event. This 

piping segment is within the scope of SLR. 

Containment heating and 

ventilation system ductwork 

downstream of the fusible 

links providing cooling to the 

steam generator compartment 

and reactor vessel annulus 

This nonsafety-related ductwork provides cooling to support 

the applicant’s environmental qualification program. However, 

the failure of the cavity cooling system ductwork will not 

prevent the satisfactory completion of any critical safety 

function during and following a DBE. Thus, this ductwork is 

not within the scope of SLR. 

Standpipe installed inside the 

fuel oil storage tank 

The standpipe as described in the applicant’s CLB ensures 

that there is sufficient fuel oil reserve for the emergency diesel 

generator to operate for the number of days specified in the 

plant technical specifications following DBEs. Therefore, this 

standpipe is within the scope of SLR. 

Insulation on boron 

injection tank 

The temperature is high enough that insulation is not 

necessary to prevent boron precipitation. The plant technical 

specifications require periodic verification of the tank 

temperature. Thus, the insulation is not relied on to ensure 

the function of the emergency system and is not within the 

scope of SLR. 

Pressurizer spray head The spray head is not credited for the mitigation of any 

accidents addressed in the UFSAR accident analyses for 

many plants. The function of the pressurizer spray is to 

reduce reactor coolant system pressure during normal 

operating conditions. However, some plants rely on this 

component for pressure control to achieve cold shutdown 

during certain fire events. Failure of the spray head should be 

evaluated in terms of any possible damage to surrounding 

safety grade components, in addition to the need for spray. 

Therefore, this component should be evaluated on a 

plant-specific basis. 

 
2.3-7 

Table 2.3-2 Examples of Mechanical Components Screening and Basis 

for Disposition 

Example Disposition 

Diesel engine jacket water heat exchanger 

and portions of the diesel fuel oil system and 

starting air system supplied by a vendor on a 

diesel generator skid 

These are “passive,” “long-lived” components 

having intended functions. They are subject 

to an AMR for SLR even though the diesel 

generator is considered “active.” 

Fuel assemblies The fuel assemblies are replaced at regular 

intervals based on the fuel cycle of the plant. 

They are not subject to an AMR. 

Valve internals (such as disk and seat) 10 CFR 54.21(a)(1)(i) excludes valves, other 

than the valve body, from AMR. The 

Statements of Consideration of the License 

Renewal Rule provide the basis for excluding 

SCs that perform their intended functions with 

moving parts or with a change in configuration 

or properties. Although the valve body is 

subject to an AMR, valve internals are not. 

 
2.3-8 

Table 2.3-3 Examples of Mechanical Component-Intended Functions 

Component Intended Function*

Piping Pressure boundary 

Valve body Pressure boundary 

Pump casing Pressure boundary 

Orifice Pressure boundary flow restriction 

Heat exchanger Pressure boundary heat transfer 

Reactor vessel internals Structural support of fuel assemblies, control 

rods, and incore instrumentation, to maintain 

core configuration and flow distribution 

*The component-intended functions are those that support the system-intended functions. For example, a heat 

exchanger in the spent fuel cooling system has a pressure boundary-intended function, but may not have a heat 

transfer function. Similarly, not all orifices have flow restriction as an intended function. 
2.4-1 

2.4 Scoping and Screening Results: Structures 

Review Responsibilities 

Primary—Assigned branch(es) 

Secondary—None 

2.4.1 Areas of Review 

This section addresses the scoping and screening results of structures and structural components 

for subsequent license renewal (SLR). Typical structures include the following: 

 The primary containment structure. 

 Building structures (such as the intake structure, diesel generator building, auxiliary 

building, and turbine building). 

 Component supports (such as cable trays, pipe hangers, elastomer vibration isolators, 

equipment frames and stanchions, and heating, ventilation, and air conditioning (HVAC) 

ducting supports). 

 Non-safety-related structures whose failure could prevent safety-related systems, 

structures, and components (SSCs) from performing their intended functions (e.g., seismic 

Category II structures over Category I structures). 

Typical structural components include the following: (i) liner plates, (ii) walls, (iii) floors, (iv) roofs, 

(v) foundations, (vi) doors, (vii) beams, (viii) columns, and (ix) frames. 

Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to identify 

and list structures and components (SCs) subject to an aging management review (AMR). These 

are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 10 CFR 54.21(a)(2) 

requires an applicant to describe and justify the methods used to identify these SCs. The 

U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s methodology separately 

following the guidance in Section 2.1. To verify that the applicant has properly implemented its 

methodology, the NRC staff focuses its review on the implementation results. Such a focus 

allows the NRC staff to confirm that there is no omission of structures that are subject to an AMR 

by the applicant. If the review identifies no omission, the NRC staff has the basis to find that there 

is reasonable assurance that the applicant has identified the SCs that are subject to an AMR. 

An applicant should list all plant-level systems and structures. On the basis of the design basis 

events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information 

relating to nonsafety-related systems and structures and certain regulated events, the applicant 

should identify those plant-level systems and structures within the scope of SLR, as defined in 

10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. The NRC 

staff reviews the applicant’s plant-level “scoping” results separately following the guidance in 

Section 2.2. 

For structures that are within the scope of SLR, an applicant must identify the SCs that are 

“passive” and “long-lived” in accordance with 10 CFR 54.21(a)(1)(i) and (ii). These “passive,” 
2.4-2 

“long-lived” SCs are subject to an AMR (“screening”). The applicant’s methodology 

implementation results for identifying SCs subject to an AMR is the area of review. 

The applicant has the flexibility to determine the set of SCs for which an AMR is performed, 

provided that this set includes the SCs for which the NRC has determined that an AMR is 

required. This flexibility is described in the Statements of Consideration for the License Renewal 

Rule (60 FR 22478). Therefore, the reviewer should not focus the review on structural 

components that the applicant has already identified as subject to an AMR because it is 

an applicant’s option to include more SCs than those subject to an AMR, pursuant to 

10 CFR 54.21(a)(1). Rather, the reviewer should focus on those SCs that are not included by the 

applicant as subject to an AMR to ensure that they do not perform an intended function as defined 

in 10 CFR 54.4(b) or are not “passive” and “long-lived.” 

2.4.2 Acceptance Criteria 

The acceptance criteria for the areas of review define methods for determining whether the 

applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the applicant’s 

implementation of its methodology to be acceptable, the NRC staff should have reasonable 

assurance that there has been no omission of SCs that are subject to an AMR. 

2.4.2.1 Structural Components Subject to an Aging Management Review 

Structural components are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are: 

 Safety-related SSCs that are relied upon to remain functional during and following DBEs 

[as defined in 10 CFR 50.49(b)(1)] to ensure the following functions: 

— The integrity of the reactor coolant pressure boundary; 

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

condition; or 

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

could result in potential offsite exposure comparable to the guidelines in 

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

 All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii). 

 All SSCs relied on in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with NRC 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). 

Structural components are subject to an AMR if they are within the scope of SLR and perform an 

intended function as defined in 10 CFR 54.4(b) without moving parts or a change in configuration 

or properties (“passive”), and are not subject to replacement based on a qualified life or specified 

time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)].
2.4-3 

2.4.3 Review Procedures 

The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

additional information from the applicant regarding why a certain structure was not identified by 

the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, the 

reviewer should provide a focused question that clearly explains what information is needed, why 

the information is needed, and how the information will allow the NRC staff to make its safety 

finding. In addition, other NRC staff members review the applicant’s scoping and screening 

methodology separately following the guidance in Section 2.1. The reviewer should keep these 

other NRC staff members informed of findings that may affect their review of the applicant’s 

methodology. The reviewer should coordinate this sharing of information through the SLR 

project manager. 

For each area of review, the following review procedures are to be followed: 

2.4.3.1 Structural Components Within the Scope of Subsequent License Renewal 

In this step, the NRC staff determines which structures and structural components are within the 

scope of subsequent license renewal. The Rule requires applicants to identify structures that are 

subject to an AMR, but not structures that are within the scope of subsequent license renewal. 

Whereas, in the past, license renewal applications have included a table of structures that are 

within the scope of SLR, that information need not be submitted with future SLR applications. 

Although that information will be available at plant sites for inspection, the reviewer should 

determine through sampling of piping and instrumentation diagram piping and instrumentation 

diagram and through review of the updated final safety analysis report (UFSAR) and other plant 

documents what portion of the components are within the scope of SLR. The reviewer should 

check to see if any structures exist that the NRC staff believes are within the scope of SLR but are 

not identified by the applicant as being subject to an AMR (and request that the applicant provide 

justification for omitting those structures that are “passive” and “long-lived”). 

2.4.3.2 Structural Components Subject to an Aging Management Review 

In general, structural components are “passive” and “long-lived.” Thus, they are subject to an 

AMR if they are within the scope of SLR. For each of the plant-level structures within the scope of 

SLR, an applicant should identify those structural components that have intended functions. For 

example, the applicant may identify that its auxiliary building is within the scope of SLR. For this 

auxiliary building, the applicant may identify the structural components of beams, concrete walls, 

blowout panels, etc., that are subject to an AMR. The applicant should justify omitting a 

component from an AMR that is within the scope of SLR at its facility and is listed as “passive” on 

Table 2.1-6. Although Table 2.1-6 is extensive, it may not be all-inclusive. Thus, the reviewer 

should use other available information, such as prior application reviews, to determine whether a 

component may be subject to an AMR. 

As set forth below, the reviewer should focus on individual structures not subject to an AMR, one 

at a time, to confirm that the structural components that have intended functions have been 

identified by the applicant. In a few instances, only portions of a particular building are within the 

scope of SLR. For example, a portion of a particular turbine building provides shelter for some 

safety-related equipment, which is an intended function, and the remainder of this particular 

building does not have any intended functions. In this case, the reviewer should verify that the 

applicant has identified the relevant particular portion of the turbine building as being within the 

scope of SLR and subject to an AMR. 
2.4-4 

The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

conditions to determine the design basis for the SSCs. The design basis specifies the intended 

function(s) of the system(s). That intended function is used to determine the components within 

that system that are relied upon for the system to perform its intended functions. 

The reviewer should focus the review on those structural components that have not been 

identified as being within the scope of SLR. For example, for a building within the scope of SLR, if 

an applicant did not identify the building roof as subject to an AMR, the reviewer should verify that 

the roof has no intended functions, such as a “Seismic Category II structures over Category I 

structures” concern in accordance with the plant’s CLB. The reviewer need not verify all structural 

components that have been identified as subject to an AMR by the applicant because the 

applicant has the option to include more structural components than the Rule requires. 

Further, the reviewer should select functions described in the UFSAR to verify that structural 

components having intended functions were not omitted from the scope of the review. For 

example, if the UFSAR indicates that a dike within the fire pump house prevents a fuel oil fire from 

spreading to the electrically driven fire pump, the reviewer should verify that this dike has been 

identified as being within the scope of SLR. Similarly, if a nonsafety-related structure or 

component is included in the plant’s CLB as a part of the safe shutdown path resulting from the 

resolution of unresolved safety issue A-46 (Ref. 1), the reviewer should verify that the structure or 

component has been included within the scope of SLR. 

The applicant should also identify the intended functions of structural components. Table 2.1-4 

provides typical “passive” structural component-intended functions. 

The NRC staff has developed additional scoping/screening guidance (Ref. 2). For example, some 

structural components may be grouped together as a commodity, such as pipe hangers, and 

some structural components are considered consumable materials, such as sealants. Additional 

guidance on these and other components are contained in Section 2.1 for the following: 

 Commodity groups 

 Hypothetical failure 

 Cascading 

 Consumables 

 Multiple functions 

If the reviewer does not identify any omissions of components from those that are subject to an 

AMR, the NRC staff would have reasonable assurance that the applicant has identified the 

components subject to an AMR for the structural systems. 

Table 2.4-1 provides examples of structural components scoping/screening lessons learned from 

the review of initial license renewal applications and the basis for disposition. 

If the applicant determines that a structural component may be subject to an AMR, the applicant 

should also identify the component’s intended functions, as defined in 10 CFR 54.4. Such 

functions must be maintained by any necessary aging management programs. 

If the reviewer determines that the applicant has satisfied the criteria described in this review 

section, the NRC staff would have reasonable assurance that the applicant has identified the 

components that are within the scope of SLR and subject to an AMR. 
2.4-5 

2.4.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the Standard Review Plan for Review of Subsequent License Renewal Applications 

for Nuclear Power Plants, then the NRC staff’s evaluation would support conclusions of the 

following type, to be included in the safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

there is reasonable assurance that the applicant has appropriately identified the 

structural components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.4.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. For a proposed alternative, the staff 

evaluates the alternative on a case-by-case basis and finds it acceptable if the staff determines 

that the alternative provides reasonable assurance that the component’s intended functions will 

be maintained. 

2.4.6 References 

1. NRC. NUREG–1211, “Regulatory Analysis for Resolution of Unresolved Safety 

Issue A-46, Seismic Qualification of Equipment in Operating Plants.” Agencywide 

Documents Access and Management System (ADAMS) Accession No. ML0311503. 

Washington, DC: U.S. Nuclear Regulatory Commission. February 1987. 

2. NRC. NUREG–0933, “Resolution of Generic Safety Issues.” Supplement 34. ADAMS 

Accession No. ML11353A382. Washington, DC: U.S. Nuclear Regulatory Commission. 

December 2011. 
2.4-6 

Table 2.4-1 Examples of Structural Components Scoping/Screening and Basis 

for Disposition 

Example Disposition 

Roof of turbine building An applicant indicates that degradation or loss of its 

turbine building roof will not result in the loss of any 

intended functions. The turbine building contains 

safety-related SSCs in the basement, which would 

remain sheltered and protected by several reinforced 

concrete floors if the turbine building roof were to 

degrade. Because this roof does not perform an 

intended function, it is not within the scope of subsequent 

license renewal. 

Post-tensioned containment 

tendon gallery 

The intended function of the post-tensioning system is to 

impose compressive forces on the concrete containment 

structure to resist the internal pressure resulting from a 

DBA with no loss of structural integrity. Although the 

tendon gallery is not relied on to maintain containment 

integrity during DBEs, operating experience indicates that 

water infiltration and high humidity in the tendon gallery 

can contribute to a significant aging effect on the vertical 

tendon anchorages that could potentially result in loss of 

the ability of the post-tensioning system to perform its 

intended function. However, containment inspections 

provide reasonable assurance that the tendon 

anchorages, including those in the gallery, will continue to 

perform their intended functions. Because the tendon 

gallery itself does not perform an intended function, it is 

not within the scope of subsequent license renewal. 

Water-stops Groundwater leakage into the auxiliary building could 

occur as a result of degradation to the water-stops. This 

leakage may cause flooding of equipment within the 

scope of subsequent license renewal. (The plant’s 

UFSAR discusses the effects of flooding.) The 

water-stops perform their functions without moving parts 

or a change in configuration, and they are not typically 

replaced. Thus, the water-stops are subject to an AMR. 

However, they need not be called out explicitly in the 

scoping/screening results if they are included as parts of 

structural components that are subject to an AMR. 
2.5-1 

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Controls Systems 

Review Responsibilities 

Primary—Assigned branch(es) 

Secondary—None 

2.5.1 Areas of Review 

This review plan section addresses the electrical and instrumentation and control (I&C) scoping 

and screening results for subsequent license renewal (SLR). Typical electrical and I&C 

components that are subject to an aging management review (AMR) for SLR include electrical 

cables and connections. 

Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to identify 

and list structures and components (SCs) subject to an AMR. These are “passive,” “long-lived” 

SCs that are within the scope of SLR. In addition, 10 CFR 54.21(a)(2) requires an applicant to 

describe and justify the methods used to identify these SCs. The U.S. Nuclear Regulatory 

Commission (NRC) staff reviews the applicant’s methodology separately following the guidance in 

Section 2.1. To verify that the applicant has properly implemented its methodology, the NRC staff 

focuses its review on the implementation results. Such a focus allows the NRC staff to confirm 

that there is no omission of electrical and I&C components that are subject to an AMR by the 

applicant. If the review identifies no omission, the NRC staff has the basis to find that there is 

reasonable assurance that the applicant has identified the electrical and I&C components that are 

subject to an AMR. 

An applicant should list all plant-level systems and structures. On the basis of the design basis 

events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information 

relating to nonsafety-related systems and structures and certain regulated events, the applicant 

would identify those plant-level systems and structures that are within the scope of SLR, as 

defined in 10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. 

The NRC staff reviews the applicant’s plant-level “scoping” results separately following the 

guidance in Section 2.2. 

For an electrical and I&C system that is within the scope of SLR, an applicant may not identify the 

specific electrical and I&C components that are subject to an AMR. For example, an applicant 

may not “tag” each specific length of cable that is “passive” and “long-lived,” and performs an 

intended function as defined in 10 CFR 54.4(b). Instead, an applicant may use the so-called 

“plant spaces” approach (Ref. 1), which is explained below. The “plant spaces” approach 

provides efficiencies in the AMR of electrical equipment located within the same plant 

space environment. 

Under the “plant spaces” approach, an applicant would identify all “passive,” “long-lived” electrical 

equipment within a specified plant space as subject to an AMR, regardless of whether these 

components perform any intended functions. For example, an applicant could identify all 

“passive,” “long-lived” electrical equipment located within the turbine building (“plant space”) as 

subject to an AMR for SLR. In the subsequent AMR, the applicant would evaluate the 

environment of the turbine building to determine the appropriate aging management activities for 

this equipment. The applicant has options to further refine this encompassing scope on an 
2.5-2 

as-needed basis. For this example, if the applicant identified elevated temperatures in a particular 

area within the turbine building, the applicant may elect to further refine the scope in this particular 

area by (1) identifying electrical equipment that is not subject to an AMR and (2) excluding this 

equipment from the AMR. In this case, the excluded electrical equipment would be reported in the 

application as not being subject to an AMR. 

Many examples of electrical and I&C components that are not considered to be “passive” and are 

not subject to an AMR for SLR are provided in 10 CFR 54.21(a)(1)(i). Therefore, the applicant is 

expected to identify only a few electrical and I&C components, such as electrical penetrations, 

cables, and connections that are “passive” and subject to an AMR. However, the time-limited 

aging analysis (TLAA) evaluation requirements in 10 CFR 54.21(c) apply to environmental 

qualification of electrical equipment, which is not limited to “passive” components. 

An applicant has the flexibility to determine the set of electrical and I&C components for which an 

AMR is performed, provided that this set includes the electrical and I&C components for which the 

NRC has determined an AMR is required. This is based on the Statements of Consideration for 

the License Renewal Rule (60 FR 22478). Therefore, the reviewer need not review all 

components that the applicant has identified as subject to an AMR because the applicant has the 

option to include more components than those required by 10 CFR 54.21(a)(1). 

2.5.2 Acceptance Criteria 

The acceptance criteria for the areas of review define methods for determining whether the 

applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the applicant’s 

implementation of its methodology to be acceptable, the NRC staff should have reasonable 

assurance that there has been no omission of electrical and I&C system components that are 

subject to an AMR. 

2.5.2.1 Components Within the Scope of Subsequent License Renewal 

Electrical and I&C components are within the scope of SLR as delineated in 10 CFR 54.4(a) if 

they are: 

 Safety-related systems, structures, and components (SSCs) that are relied upon to remain 

functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the 

following functions: 

— The integrity of the reactor coolant pressure boundary; 

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

condition; or 

— The capability to prevent or mitigate the consequences of accidents that could 

result in potential offsite exposure comparable to the guidelines in 

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

 All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii) or (iii). 
2.5-3 

 All SSCs relied on in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with NRC regulations for fire protection (10 CFR 50.48), 

environmental qualification (EQ) (10 CFR 50.49), pressurized thermal shock 

(10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout 

(SBO) (10 CFR 50.63). 

2.5.2.1.1 Components Within the Scope of SBO (10 CFR 50.63) 

Both the offsite and onsite power systems are relied upon to meet the requirements of the 

SBO Rule. This includes the following: 

 The onsite power system meeting the requirements under 10 CFR 54.4(a)(1) 

(safety-related systems). 

 Equipment that is required to cope with an SBO (e.g., alternate ac power sources) meeting 

the requirements under 10 CFR 54.4(a)(3). 

 The plant system portion of the offsite power system that is used to connect the plant to 

the offsite power source meeting the requirements under 10 CFR 54.4(a)(3). The 

electrical distribution equipment out to the first circuit breaker with the offsite distribution 

system (i.e., equipment in the switchyard). This path typically includes the circuit breakers 

that connect to the offsite system power transformers (startup transformers), the 

transformers themselves, the intervening overhead or underground circuits between circuit 

breaker and transformer and transformer and onsite electrical distribution system, and the 

associated control circuits and structures. However, the NRC staff's review is based on 

the plant-specific CLB, regulatory requirements, and offsite power design configurations. 

2.5.2.2 Components Subject to an Aging Management Review 

Electrical and I&C components are subject to an AMR if they are within the scope of SLR and 

perform an intended function as defined in 10 CFR 54.4(b) without moving parts or without a 

change in configuration or properties (“passive”), and are not subject to replacement based on a 

qualified life or specified time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)]. 

2.5.3 Review Procedures 

The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

additional information from the applicant regarding why a certain component was not identified by 

the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, the 

reviewer should provide a focused question that clearly explains what information is needed, why 

the information is needed, and how the information will allow the NRC staff to make its safety 

finding. In addition, other NRC staff members review the applicant’s scoping and screening 

methodology separately following the guidance in Section 2.1. The reviewer should keep these 

other NRC staff members informed of findings that may affect their review of the applicant’s 

methodology. The reviewer should coordinate this sharing of information through the SLR 

project manager. 

The reviewer should verify that an applicant has identified in the SLR application the electrical and 

I&C components that are subject to an AMR for its plant. The review procedures are presented 

below and assume that the applicant has performed “scoping” and “screening” of electrical and 

I&C system components in that sequence. However, the applicant may elect to perform 
2.5-4 

“screening” before “scoping,” which is acceptable because, regardless of the sequence, the end 

result should encompass the electrical and I&C components that are subject to an AMR. 

Some of the electrical equipment that is in the scope of 10 CFR 50.49 that have a qualified life of 

40 years or greater are also within the scope of SLR under 10 CFR 54.4(a)(3). They have already 

been identified by licenses under 10 CFR 50.49(b). Licensees may rely upon their listing of EQ 

equipment, as required by 10 CFR 50.49(d), for the purposes of identifying electrical equipment 

satisfying 10 CFR 54.4(a)(3) that is also within the scope of 10 CFR 50.49 (60 FR 22466). 

However, the License Renewal Rule has a requirement [10 CFR 54.21(c)] on the evaluation of 

TLAAs, including EQ (10 CFR 50.49). EQ equipment is not limited to “passive” equipment. The 

applicant may identify EQ equipment separately for TLAA evaluation and not include such 

equipment as subject to an AMR under 10 CFR 54.21(a)(1). The EQ equipment identified for 

TLAA evaluation would include the “passive” EQ equipment subject to an AMR. The TLAA 

evaluation would ensure that the EQ equipment would be functional for the subsequent period of 

extended operation. The NRC staff reviews the applicant’s EQ TLAA evaluation separately 

following the guidance in Section 4.4. 

For each area of review, the following review procedures are to be followed. 

2.5.3.1 Components Within the Scope of Subsequent License Renewal 

In this step, the NRC staff determines whether the applicant has properly identified the 

components that are within the scope of SLR. The Rule requires that the subsequent license 

renewal application (SLRA) identify and list components that are within the scope of SLR and are 

subject to an AMR. Whereas, in the past, license renewal applications have included a table of 

components that are within the scope of SLR, generally that information need not be submitted 

with future SLRAs. Although that information will be available at plant sites for inspection, the 

reviewer must determine, through sampling of one-line diagrams and through review of the 

updated final safety analysis report (UFSAR) and other plant documents, what portion of the 

components are within the scope of SLR. The reviewer must check to see if any components 

exist that the NRC staff believes are within the scope but are not identified by the applicant as 

being subject to AMR (any request that the applicant provide justification for omitting those 

components that are “passive” and “long-lived”). 

The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

conditions to determine the design basis for the SSCs. The design basis specifies the intended 

function(s) of the system(s). That intended function is used to determine the components within 

that system that are required for the system to perform its intended functions. 

The applicant may use the “plant spaces” approach in scoping electrical and I&C components for 

SLR. In the “plant spaces” approach, an applicant may indicate that all electrical and I&C 

components located within a particular plant area (“plant space”), such as the containment and 

auxiliary building, are within the scope of SLR. The applicant may also indicate that all electrical 

and I&C components located within another plant area (“plant space”), such as the warehouse, 

are not within the scope of SLR. Table 2.5-1 contains examples of this “plant spaces” approach 

and the corresponding review procedures. 

The applicant would use the “plant spaces” approach for the subsequent AMR of the electrical 

and I&C components. The applicant would evaluate the environment of the “plant spaces” to 

determine the appropriate aging management activities for equipment located there. The 

applicant has the option to further refine this encompassing scope on an as-needed basis. For 
2.5-5 

example, if the applicant identified elevated temperatures in a particular area within a building 

(“plant space”), the applicant may elect to identify only those “passive,” “long-lived” electrical and 

I&C components that perform an intended function in this particular area as subject to an AMR. 

This approach of limiting the “plant spaces” is consistent with the “plant spaces” approach. In this 

case, the reviewer verifies that the applicant has specifically identified the electrical and I&C 

components that may be within the scope of SLR in these limited “plant spaces.” The reviewer 

should verify that the electrical and I&C components that the applicant has elected to further 

exclude do not indeed have any intended functions as defined in 10 CFR 54.4(b). 

Section 2.1 contains additional guidance on scoping the following: 

 Commodity groups 

 Complex assemblies 

 Scoping events 

 Hypothetical failure 

 Cascading 

If the reviewer does not identify any omissions of components from those that are within the scope 

of SLR, the NRC staff would have reasonable assurance that the applicant has identified the 

components within the scope of SLR for the electrical and I&C systems. 

2.5.3.2 Components Subject to an Aging Management Review 

In this step, the reviewer determines whether the applicant has properly identified the components 

subject to an AMR from among those which are within the scope of SLR (i.e., those identified in 

Subsection 2.5.3.1). The reviewer should review selected components that the applicant has 

identified as being within the scope of SLR to verify that the applicant has identified these 

components as being subject to an AMR if they perform intended functions without moving parts 

or without a change in configuration or properties and are not subject to replacement on the basis 

of a qualified life or specified time period. The description of “passive” may also be interpreted to 

include structures and components that do not display “a change in state.” 

Only components that are “passive” and “long-lived” are subject to an AMR. Table 2.1-6 lists 

many typical components and structures, and their associated intended functions, and identifies 

whether they are “passive.” The reviewer should use Table 2.1-6 in identifying whether certain 

components are “passive.” The reviewer should verify that electrical and I&C components 

identified as “passive” in Table 2.1-6 have been included by the applicant as being subject to an 

AMR. Although Table 2.1-6 is extensive, it may not be all-inclusive. Thus, the reviewer should 

use other available information sources, such as prior application reviews, to determine whether a 

component may be subject to an AMR. 

Section 2.1 contains additional guidance on screening the following: 

 Consumables 

 Multiple intended functions 

If the reviewer does not identify any omissions of components from those that are subject to an 

AMR, the NRC staff would have reasonable assurance that the applicant has identified the 

components subject to an AMR for the electrical and I&C systems. 
2.5-6 

2.5.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the Standard Review Plan for Review of Subsequent License Renewal Applications 

for Nuclear Power Plants, then the NRC staff’s evaluation would support conclusions of the 

following type, to be included in the safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that there 

is reasonable assurance that the applicant has appropriately identified the 

electrical and instrumentation and controls system components subject to an AMR 

in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.5.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. For a proposed alternative, the staff 

evaluates the alternative on a case-by-case basis and finds it acceptable if the staff determines 

that the alternative provides reasonable assurance that the component’s intended functions will 

be maintained. 

2.5.6 References 

1. SNL. SAND96-0344, “Aging Management Guideline for Commercial Nuclear Power 

Plants-Electrical Cable and Terminations.” Agencywide Documents Access and 

Management System (ADAMS) Accession No. ML031140264. Albuquerque, 

New Mexico: Sandia National Laboratories. September 1996. 
2.5-7 

Table 2.5-1 Examples of “Plant Spaces” Approach for Electrical and I&C 

Scoping and Corresponding Review Procedures 

Example Review Procedures 

An applicant indicates that all 

electrical and I&C components 

on site are within the scope 

of SLR. 

This is acceptable, and a review is not necessary because 

all electrical and I&C components are included without 

exception and would include those required by the Rule. 

An applicant indicates that all 

electrical and I&C components 

located in seven specific 

buildings (containment, auxiliary 

building, turbine building, etc.) 

are within the scope of SLR. 

The reviewer should review electrical systems and 

components in areas outside of these seven buildings (“plant 

spaces”). The reviewer should verify that the applicant has 

included any direct-buried cables in trenches between these 

buildings as within the scope of SLR if they perform an 

intended function. The reviewer should also select buildings 

other than the seven indicated (for example, the radwaste 

facility) to verify that they do not contain any electrical and 

I&C components that perform any intended functions. 

An applicant indicates that all 

electrical and I&C components 

located onsite, except for the 

525 kV switchyard, 230 kV 

transmission lines, radwaste 

facility, and 44 kV substation, 

are within the scope of SLR. 

The reviewer should select the specifically excluded “plant 

spaces” (that is, the 525 kV switchyard, 230 kV transmission 

lines, radwaste facility, and 44 kV substation) to verify that 

they do not contain any electrical and I&C components that 

perform any intended functions. 

3.1-1 

3 AGING MANAGEMENT REVIEW 

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

Review Responsibilities 

Primary—The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.1.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management programs (AMPs) of the reactor vessel, internals, and reactor coolant system. For a 

recent vintage plant, the information related to the reactor vessel, internals, and reactor coolant 

system is contained in Chapter 5, “Reactor Coolant System and Connected Systems,” of the 

plant’s final safety analysis report (FSAR), consistent with the “Standard Review Plan (SRP) for 

the Review of Safety Analysis Reports for Nuclear Power Plants” (NUREG–0800). For older 

plants, the location of applicable information is plant-specific because an older plant’s FSAR may 

have predated NUREG–0800. 

The reactor vessel, internals, and reactor coolant system includes the reactor vessel and 

internals. For boiling water reactors (BWRs), this system also includes the reactor coolant 

recirculation system and portions of other systems connected to the pressure vessel extending to 

the first isolation valve outside of containment or to the first anchor point. These connected 

systems include residual heat removal, low-pressure core spray, high-pressure core spray, 

low-pressure coolant injection, high-pressure coolant injection, reactor core isolation cooling, 

isolation condenser, reactor coolant cleanup, feedwater, and main steam. For pressurized water 

reactors (PWRs), the reactor coolant system includes the primary coolant loop, the pressurizer, 

and the steam generators (SGs). For PWRs the reactor coolant system also includes the 

pressurizer relief tank, which is not an American Society of Mechanical Engineers Boiler and 

Pressure Vessel Code (ASME Code) Class 1 component. The connected systems for PWRs 

include the residual heat removal or low pressure injection system, core flood spray or safety 

injection tank, chemical and volume control system or high-pressure injection system, and 

sampling system. 

The responsible review organization is to review the following subsequent license renewal 

application (SLRA) AMR and AMP items assigned to it, per Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) Section 1.2: 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 

 AMR results not consistent with or not addressed in the GALL-SLR Report 
3.1-2 

AMPs 

 Consistent with GALL-SLR Report AMPs (including those with enhancements and/or 

exceptions) 

 Plant-specific AMPs

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.1.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

3.1.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The AMR and the AMPs applicable to the reactor vessel, internals, and reactor coolant system 

are described and evaluated in Chapter IV of the GALL-SLR Report. 

The applicant’s SLRA should provide sufficient information so that the reviewer is able to confirm 

that the specific SLRA AMR item and the associated SLRA AMP are consistent with the cited 

GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

consistent with the GALL-SLR Report AMR item to which it is compared. When the applicant is 

crediting a different AMP than recommended in the GALL-SLR Report, the reviewer should 

confirm that the alternate AMP is valid to use for aging management and will be capable of 

managing the effects of aging as adequately as the AMP recommended by the GALL-SLR 

Report. 

3.1.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria defined in Subsection 3.1.2.1 need to be applied first for all of 

the AMRs and AMPs reviewed as part of this section. In addition, if further evaluation is 

recommended, then additional criteria apply for each of the following aging effect/aging 

mechanism combinations. Refer to Table 3.1-1, comparing the “Further Evaluation 

Recommended” and the “GALL-SLR” column, for the AMR items that reference the 

following subsections. 

3.1.2.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be time-limited 

aging analyses (TLAAs), as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). These types of TLAAs are addressed separately in 

Section 4.3, “Metal Fatigue,” of this SRP-SLR. For plant-specific cumulative usage factor 

calculations that are based on stress-based input methods, the methods are to be appropriately 

defined and discussed in the applicable TLAAs. 
3.1-3 

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

1. Loss of material due to general, pitting, and crevice corrosion could occur in the steel 

PWR SG upper and lower shell and transition cone exposed to secondary feedwater and 

steam. The existing program relies on control of water chemistry to mitigate corrosion 

and inservice inspection (ISI) to detect loss of material. The extent and schedule of the 

existing SG inspections are designed to ensure that flaws cannot attain a depth sufficient 

to threaten the integrity of the welds. However, according to NRC Information Notice 

(IN) 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam 

Generators,” the program may not be sufficient to detect pitting and crevice corrosion if 

general and pitting corrosion of the shell is known to exist. Augmented inspection is 

recommended to manage this aging effect. Furthermore, this issue is limited to 

Westinghouse Model 44 and 51 Steam Generators, where a high-stress region exists at 

the shell to transition cone weld. Acceptance criteria are described in Branch Technical 

Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR). 

2. Loss of material due to general, pitting, and crevice corrosion could occur in the steel 

PWR steam generator shell assembly exposed to secondary feedwater and steam. The 

existing program relies on control of secondary water chemistry to mitigate corrosion. 

However, some applicants have replaced only the bottom part of their recirculating SGs, 

generating a cut in the middle of the transition cone, and, consequently, a new transition 

cone closure weld. It is recommended that volumetric examinations be performed in 

accordance with the requirements of ASME Code Section XI for upper shell and lower 

shell-to-transition cones with gross structural discontinuities for managing loss of 

material due to general, pitting, and crevice corrosion in the welds for Westinghouse 

Model 44 and 51 SGs, where a high-stress region exists at the shell-to-transition 

cone weld. 

The new continuous circumferential weld, resulting from cutting the transition cone as 

discussed above, is a different situation from the SG transition cone welds containing 

geometric discontinuities. Control of water chemistry does not preclude loss of material 

due to pitting and crevice corrosion at locations of stagnant flow conditions. The new 

transition area weld is a field weld as opposed to having been made in a controlled 

manufacturing facility, and the surface conditions of the transition weld may result in flow 

conditions more conducive to initiation of general, pitting, and crevice corrosion than those 

of the upper and lower transition cone welds. Crediting of the ISI program for the new SG 

transition cone weld may not be an effective basis for managing loss of material in this 

weld, as the ISI criteria would only perform a VT-2 visual leakage examination of the weld 

as part of the system leakage test performed pursuant to ASME Code Section XI 

requirements. In addition, ASME Code Section XI does not require licensees to remove 

insulation when performing visual examination on nonborated treated water systems. 

Therefore, the effectiveness of the chemistry control program should be verified to ensure 

that loss of material due to general, pitting and crevice corrosion is not occurring. 

For the new continuous circumferential weld, further evaluation is recommended to verify 

the effectiveness of the chemistry control program. A one-time inspection at susceptible 

locations is an acceptable method to determine whether an aging effect is not occurring or 

an aging effect is progressing very slowly, such that the component’s intended function will 

be maintained during the subsequent period of extended operation. Furthermore, this 

issue is limited to replacement of recirculating SGs with a new transition cone 

closure weld. 
3.1-4 

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

1. Neutron irradiation embrittlement is a TLAA to be evaluated for the subsequent period of 

extended operation for all ferritic materials that have a neutron fluence greater than 

1017 n/cm2 (E >1 MeV) at the end of the subsequent period of extended operation. 

Certain aspects of neutron irradiation embrittlement are TLAAs as defined in 

10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). This TLAA is addressed separately in Section 4.2, “Reactor 

Pressure Vessel Neutron Embrittlement Analysis,” of this SRP-SLR. 

2. Loss of fracture toughness due to neutron irradiation embrittlement could occur in BWR 

and PWR reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and 

neutron flux. A reactor vessel material surveillance program monitors neutron irradiation 

embrittlement of the reactor vessel. The reactor vessel material surveillance program is 

either a plant-specific surveillance program or an integrated surveillance program, 

depending on matters such as the composition of limiting materials and the availability of 

surveillance capsules. 

In accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its 

proposed withdrawal schedule for approval prior to implementation. Untested capsules 

placed in storage must be maintained for future insertion. Thus, further NRC staff 

evaluation is required for a subsequent license renewal (SLR). Specific 

recommendations for an acceptable AMP are provided in GALL-SLR Report 

AMP XI.M31, “Reactor Vessel Material Surveillance.” 

A neutron fluence monitoring program may be used to monitor the neutron fluence levels 

that are used as the time-dependent inputs for the plant’s reactor vessel neutron 

irradiation embrittlement TLAAs. These TLAAs are the subjects of the topics discussed in 

SRP-SLR Section 3.1.2.2.3.1 and “acceptance criteria” and “review procedure” guidance 

in SRP-SLR Section 4.2. For those applicants that determine it is appropriate to include a 

neutron fluence monitoring AMP in their SLRAs, the program is to be implemented in 

conjunction with the applicant’s implementation of an AMP that corresponds to GALL-SLR 

Report AMP XI.M31, “Reactor Vessel Material Surveillance.” Specific recommendations 

for an acceptable neutron fluence monitoring AMP are provided in GALL-SLR Report 

AMP X.M2, “Neutron Fluence Monitoring.” 

3. Reduction in Fracture Toughness is a plant-specific TLAA for Babcock & Wilcox (B&W) 

reactor internals to be evaluated for the subsequent period of extended operation in 

accordance with the NRC staff’s safety evaluation concerning “Demonstration of the 

Management of Aging Effects for the Reactor Vessel Internals,” B&W Owners Group 

report number BAW-2248, which is included in BAW-2248A, March 2000. Plant-specific 

TLAAs are addressed in Section 4.7, “Other Plant-Specific Time-Limited Aging 

Analyses,” of this SRP-SLR. 

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

Corrosion Cracking 

1. Cracking due to stress corrosion cracking (SCC) and intergranular stress corrosion 

cracking (IGSCC) could occur in stainless steel (SS) and nickel alloy reactor vessel (RV) 

flange leak detection lines of BWR light-water reactor facilities. The plant-specific 

operating experience (OE) and condition of the RV flange leak detection lines are 
3.1-5 

evaluated to determine if SCC or IGSCC has occurred. The aging effect of cracking in 

SS and nickel alloy RV flange leak detection lines is not applicable and does not require 

management if (a) the plant-specific OE does not reveal a history of SCC or IGSCC and 

(b) a one-time inspection demonstrates that the aging effect is not occurring. The 

applicant documents the results of the plant-specific OE review in the SLRA. GALL-SLR 

Report AMP XI.M32, “One-Time Inspection,” describes an acceptable program to 

demonstrate that cracking is not occurring. If cracking has occurred, GALL-SLR Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” describes an 

acceptable program to manage cracking in RV flange leak detection lines. 

2. Cracking due to SCC and IGSCC could occur in SS BWR isolation condenser 

components exposed to reactor coolant. The existing program relies on control of 

reactor water chemistry to mitigate SCC and on ASME Code Section XI ISI to detect 

cracking. However, the existing program should be augmented to detect cracking due to 

SCC and IGSCC. An augmented program is recommended to include temperature and 

radioactivity monitoring of the shell-side water and eddy current testing of tubes to 

ensure that the component’s intended function will be maintained during the subsequent 

period of extended operation. Acceptance criteria are described in BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 

3.1.2.2.5 Crack Growth Due to Cyclic Loading 

Crack growth due to cyclic loading could occur in reactor pressure vessel (RPV) shell forgings 

clad with SS using a high-heat-input welding process. Therefore, the current licensing basis 

(CLB) may include flaw growth evaluations of intergranular separations (i.e., underclad cracks) 

that have been identified in the RPV-to-cladding welds for the vessel. The evaluations apply to 

SA-508 Class 2 RPV forging components where the cladding was deposited and welded to the 

vessel using a high-heat-input welding process. Tor CLBs that include these types of evaluations, 

the evaluations may need to be identified as TLAAs if they are determined to conform to the six 

criteria for defining TLAAs in 10 CFR 54.3(a). The methodology for evaluating the underclad flaw 

should be consistent with the flaw evaluation procedure and criterion in the ASME Code 

Section XI2. See SRP-SLR, Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses,” for 

generic guidance for meeting the requirements of 10 CFR 54.21(c). 

3.1.2.2.6 Cracking Due to Stress Corrosion Cracking 

1. Cracking due to SCC could occur in PWR SS bottom-mounted instrument guide tubes 

exposed to reactor coolant. Further evaluation is recommended to ensure that these 

aging effects are adequately managed. A plant-specific AMP should be evaluated to 

ensure that this aging effect is adequately managed. Acceptance criteria are described 

in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

2. Cracking due to SCC could occur in Class 1 PWR cast austenitic stainless steel (CASS) 

reactor coolant system piping and piping components exposed to reactor coolant. The 

existing program relies on control of water chemistry to mitigate SCC; however, SCC 

could occur in CASS components that do not meet the NUREG–0313, “Technical Report 

on Material Selection and Process Guidelines for BWR Coolant Pressure Boundary 

Piping” guidelines with regard to ferrite and carbon content. Further evaluation is 

 

2Refer to the GALL-SLR Report, Chapter I, for applicability of other editions of the ASME Code, Section XI. 
3.1-6 

recommended of a plant-specific program for these components to ensure that this 

aging effect is adequately managed. Acceptance criteria are described in BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 

3. Cracking due to SCC could occur in SS or nickel alloy RV flange leak detection lines of 

PWR light-water reactor facilities. The plant-specific OE and condition of the RV flange 

leak detection lines are evaluated to determine if SCC has occurred. The aging effect of 

cracking in SS and nickel alloy RV flange leak detection lines is not applicable and does 

not require management if (a) the plant-specific OE does not reveal a history of SCC 

and (b) a one-time inspection demonstrates that the aging effect is not occurring. The 

applicant documents the results of the plant-specific OE review in the SLRA. GALL-SLR 

Report AMP XI.M32, “One-Time Inspection,” describes an acceptable program to 

demonstrate that cracking is not occurring. If cracking has occurred, GALL-SLR Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” describes an 

acceptable program to manage cracking in RV flange leak detection lines. 

3.1.2.2.7 Cracking Due to Cyclic Loading 

Cracking due to cyclic loading could occur in steel and SS BWR isolation condenser components 

exposed to reactor coolant. The existing program relies on ASME Code Section XI ISI. However, 

the existing program should be augmented to detect cracking due to cyclic loading. An 

augmented program is recommended to include temperature and radioactivity monitoring of the 

shell-side water and eddy current testing of tubes to ensure that the component’s intended 

function will be maintained during the subsequent period of extended operation. Acceptance 

criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.1.2.2.8 Loss of Material Due to Erosion 

Loss of material due to erosion could occur in steel steam generator feedwater impingement 

plates and supports exposed to secondary feedwater. Further evaluation is recommended of a 

plant-specific AMP to ensure that this aging effect is adequately managed. Acceptance criteria 

are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.1.2.2.9 Aging Management of Pressurized Water Reactor Vessel Internals (Applicable to 

Subsequent License Renewal Periods Only) 

Electric Power Research Institute (EPRI) Topical Report (TR)-1022863, “Materials Reliability 

Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

(MRP-227-A)” (Agencywide Documents Access and Management System (ADAMS) Accession 

Nos. ML12017A191 through ML12017A197 and ML12017A199), provides the industry’s current 

aging management recommendations for the reactor vessel internal (RVI) components that are 

included in the design of a PWR facility. In this report, the EPRI Materials Reliability Program 

(MRP) identified that the following aging mechanisms may be applicable to the design of the RVI 

components in these types of facilities: (a) SCC, (b) irradiation-assisted stress corrosion cracking 

(IASCC), (c) fatigue, (d) wear, (e) neutron irradiation embrittlement, (f) thermal aging 

embrittlement, (g) void swelling and irradiation growth, or (h) thermal or irradiation-enhanced 

stress relaxation or irradiation enhanced creep. The methodology in MRP-227-A was 

approved by the NRC in a safety evaluation dated December 16, 2011 (ADAMS Accession 

No. ML11308A770), which includes those plant-specific applicant/licensee action items that a 

licensee or applicant applying the MRP-227-A report would need to address and resolve and 

apply to its licensing basis. 
3.1-7 

The EPRI MRP’s functionality analysis and failure modes, effects, and criticality analysis bases for 

grouping Westinghouse-designed, B&W-designed and Combustion Engineering (CE)-designed 

RVI components into these inspection categories was based on an assessment of aging effects 

and relevant time-dependent aging parameters through a cumulative 60-year licensing period 

(i.e., 40 years for the initial operating license period plus an additional 20 years during the initial 

period of extended operation). The EPRI MRP has not assessed whether operation of 

Westinghouse-designed, B&W-designed and CE-designed reactors during an SLR operating 

period would have any impact on the existing susceptibility rankings and inspection 

categorizations for the RVI components in these designs, as defined in MRP-227-A or its 

applicable MRP background documents (e.g., MRP-191 for Westinghouse-designed or 

CE-designed RVI components or MRP-189 for B&W-designed components). 

As described in GALL-SLR Report AMP XI.M16A, the applicant may use the MRP-227-A based 

AMP as an initial reference basis for developing and defining the AMP that will be applied to the 

RVI components for the subsequent period of extended operation. However, to use this 

alternative basis, GALL-SLR Report AMP XI.M16A recommends that the MRP-227-A based AMP 

be enhanced to include a gap analysis of the components that are within the scope of the AMP. 

The gap analysis is a basis for identifying and justifying any potential changes to the MRP-227-A 

based program that may be necessary to provide reasonable assurance that the effects of 

age-related degradation will be managed during the subsequent period of extended operation. 

The criteria for the gap analysis are described in GALL-SLR Report AMP XI.M16A. 

Alternatively, the PWR SLRA may define a plant-specific AMP for the RVI components to 

demonstrate that the RVI components will be managed in accordance with the requirements of 

10 CFR 54.21(a)(3) during the proposed subsequent period of extended operation. Components 

to be inspected, parameters monitored, monitoring methods, inspection sample size, frequencies, 

expansion criteria, and acceptance criteria are justified in the SLRA. The NRC staff will assess 

the adequacy of the plant-specific AMP against the criteria for the 10 AMP program elements that 

are defined in Section A.1.2.3 of SRP-SLR Appendix A.1.

3.1.2.2.10 Loss of Material Due to Wear 

1. Industry OE indicates that loss of material due to wear can occur in PWR control rod 

drive (CRD) head penetration nozzles made of nickel alloy due to the interactions 

between the nozzle and the thermal sleeve centering pads of the nozzle (see Ref. 29). 

The CRD head penetration nozzles are also called control rod drive mechanism (CRDM) 

nozzles or CRDM head adapter tubes. The applicant should perform a further 

evaluation to confirm the adequacy of a plant-specific AMP or analysis (with any 

necessary inspections) for management of the aging effect. The applicant may use the 

acceptance criteria, which are described in BTP RLSB-1 (Appendix A.1 of this 

SRP-SLR), to demonstrate the adequacy of a plant-specific AMP. Alternatively, the 

applicant may perform an analysis with any necessary inspections to confirm that loss of 

material due to wear does not affect the intended function(s) of these CRD head 

penetration nozzles, consistent with the current licensing basis (CLB). 

2. Industry OE indicates that loss of material due to wear can occur in the SS thermal 

sleeves of PWR CRD head penetration nozzles due to the interactions between the 

nozzle and the thermal sleeve (e.g., where the thermal sleeve exits from the head 

penetration nozzle inside the reactor vessel as described in Ref. 30). Therefore, the 

applicant should perform a further evaluation to confirm the adequacy of a plant-specific 

AMP for management of the aging effect. The applicant may use the acceptance 
3.1-8 

criteria, which are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR), to 

demonstrate the adequacy of a plant-specific AMP.

3.1.2.2.11 Cracking Due to Primary Water Stress Corrosion Cracking 

1. Foreign OE in steam generators with a design similar to that of Westinghouse steam 

generators (particularly Model 51) has identified cracks due to primary water stress 

corrosion cracking (PWSCC) in steam generator (SG) divider plate assemblies 

fabricated of Alloy 600 and/or the associated Alloy 600 weld materials, even with proper 

primary water chemistry. Cracks have been detected in the stub runner with depths 

typically about 0.08 inches (EPRI 3002002850). 

 All but one of these instances of cracking has been detected in divider plate assemblies 

that are approximately 1.3 inches in thickness. For the cracks in the 1.3-inch thick divider 

plate assemblies, the cracks tend to be parallel to the divider-plate-to-stub-runner weld 

(i.e., run horizontally in parallel to the lower surface of the tubesheet). For the one 

instance of cracking in a divider plate assembly with a thickness greater than 1.3 inches, 

the cracking occurred in a divider plate assembly with a thickness of approximately 

2.4 inches near manufacturing marks on the upper end of the stub runner used for locating 

tubesheet holes. These flaws were estimated to be approximately 0.08-inch deep. 

 Although these instances indicate that the water chemistry program may not be sufficient 

to manage cracking due to PWSCC in SG divider plate assemblies, analyses by the 

industry indicate that PWSCC in the divider plate assembly does not pose a structural 

integrity concern for other steam generator components (e.g., tubesheet and tube-totubesheet welds) and does not adversely affect other safety analyses (e.g., analyses 

supporting tube plugging and repairs, tube repair criteria, and design basis accidents). In 

addition, the industry analyses indicate that flaws in the divider plate assembly will not 

adversely affect the heat transfer function (as a result of bypass flow) during normal forced 

flow operation, during natural circulation conditions (assessed in the analyses of various 

design basis accidents), or in the event of a loss-of-coolant accident (LOCA). 

 Furthermore, additional industry analyses indicate that PWSCC in the divider plate 

assembly is unlikely to adversely impact adjacent items, such as the tubesheet cladding, 

tube-to-tubesheet welds, and channel head. Therefore, 

 For units with divider plate assemblies fabricated of Alloy 690 and Alloy 690 type 

weld materials, a plant-specific AMP is not necessary. 

 For units with divider plate assemblies fabricated of Alloy 600 or Alloy 600 type 

weld materials, if the analyses performed by the industry (EPRI 3002002850) are 

applicable and bounding for the unit, a plant-specific AMP is not necessary. 

 For units with divider plate assemblies fabricated of Alloy 600 or Alloy 600 type 

weld materials, if the industry analyses (EPRI 3002002850) are not bounding for 

the applicant’s unit, a plant-specific AMP is necessary or a rationale is necessary 

for why such a program is not needed. A plant-specific AMP (one beyond the 

primary water chemistry and the steam generator programs) may include a 

one-time inspection that is capable of detecting cracking to verify the effectiveness 

of the water chemistry and steam generator programs and the absence of PWSCC 

in the divider plate assemblies. 
3.1-9 

 The existing programs rely on control of reactor water chemistry to mitigate cracking 

due to PWSCC and general visual inspections of the channel head interior surfaces 

(included as part of the steam generator program). The GALL-SLR Report recommends 

further evaluation for a plant-specific AMP to confirm the effectiveness of the primary 

water chemistry and steam generator programs as described in this section. Acceptance 

criteria for a plant-specific AMP are described in BTP RLSB-1 (Appendix A.1 of this 

SRP-SLR). In place of a plant-specific AMP, the applicant may provide a rationale to 

justify why a plant-specific AMP is not necessary. 

2. Cracking due to PWSCC could occur in SG nickel alloy tube-to-tubesheet welds 

exposed to reactor coolant. The acceptance criteria for this review are: 

 For units with Alloy 600 SG tubes for which an alternate repair criterion such as C*, 

F*, H*, or W* has been permanently approved for both the hot- and cold-leg side of 

the steam generator, the weld is no longer part of the reactor coolant pressure 

boundary and a plant-specific AMP is not necessary; 

 For units with Alloy 600 steam generator tubes, if there is no permanently 

approved alternate repair criteria such as C*, F*, H*, or W*, or permanent 

approval applies to only either the hot- or cold-leg side of the steam generator, 

a plant-specific AMP is necessary; 

 For units with thermally treated Alloy 690 SG tubes and with tubesheet cladding 

using Alloy 690 type material, a plant-specific AMP is not necessary; 

 For units with thermally treated Alloy 690 SG tubes and with tubesheet cladding 

using Alloy 600 type material, a plant-specific AMP is necessary unless the 

applicant confirms that the industry’s analyses for tube-to-tubesheet weld cracking 

(e.g., chromium content for the tube-to-tubesheet welds is approximately 

22 percent and the tubesheet primary face is in compression as discussed in 

EPRI 3002002850) are applicable and bounding for the unit, and the applicant will 

perform general visual inspections of the tubesheet region looking for evidence of 

cracking (e.g., rust stains on the tubesheet cladding) as part of the steam 

generator program. In lieu of a plant-specific AMP, the applicant may provide a 

rationale for why a plant-specific AMP is not necessary. 

The existing programs rely on control of reactor water chemistry to mitigate cracking due 

to PWSCC and visual inspections of the steam generator head interior surfaces. Along 

with the primary water chemistry and steam generator programs, a plant-specific AMP 

should be evaluated to confirm the effectiveness of the primary water chemistry and 

steam generator programs in certain circumstances. A plant-specific AMP may include 

a one-time inspection that is capable of detecting cracking to confirm the absence of 

PWSCC in the tube-to-tubesheet welds. Acceptance criteria for a plant-specific 

AMP are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). In place of a 

plant-specific AMP, the applicant may provide a rationale to justify why a plant-specific 

AMP is not necessary. 
3.1-10 

3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking 

GALL-SLR Report AMP XI.M9, “BWR Vessel Internals,” manages aging degradation of nickel 

alloy and SS, including associated welds, which are used in BWR vessel internal components. 

When exposed to the BWR vessel environment, these materials can experience cracking due to 

IASCC. The existing Boiling Water Reactor Vessel and Internals Project (BWRVIP) examination 

guidelines are mainly based on aging evaluation of BWR vessel internals for operation up to 

60 years. However, increases in neutron fluence during the SLR term may need to be assessed 

for supplemental inspections of BWR vessel internals to adequately manage cracking due to 

IASCC. Therefore, the applicant should perform an evaluation to determine whether 

supplemental inspections are necessary in addition to those recommended in the existing 

BWRVIP examination guidelines. If the applicant determines that supplemental inspections are 

not necessary, the applicant should provide adequate technical justification for the determination. 

If supplemental inspections are determined necessary for BWR vessel internals, the applicant 

identifies the components to be inspected and performs supplemental inspections to adequately 

manage IASCC. In addition, the applicant should confirm the adequacy of any necessary 

supplemental inspections and enhancements to the BWR Vessel Internals Program. 

3.1.2.2.13 Loss of Fracture Toughness Due to Neutron Irradiation or Thermal 

Aging Embrittlement 

GALL-SLR Report AMP XI.M9 manages aging degradation of nickel alloy and SS, including 

associated welds, which are used in BWR vessel internal components. When exposed to the 

BWR vessel environment, these materials can experience loss of fracture toughness due to 

neutron irradiation embrittlement. In addition, CASS, precipitation-hardened (PH) martensitic SS 

(e.g., 15-5 and 17-4 PH steel) and martensitic SS (e.g., 403, 410, 431 steel) can experience loss 

of fracture toughness due to neutron irradiation or thermal aging embrittlement. 

The existing BWRVIP examination guidelines are mainly based on aging evaluation of BWR 

vessel internals for operation up to 60 years. Increases in neutron fluence and thermal 

embrittlement during the SLR term may need to be assessed for supplemental inspections of 

BWR vessel internals to adequately manage loss of fracture toughness due to neutron irradiation 

or thermal aging embrittlement. Therefore, the applicant should perform an evaluation to 

determine whether supplemental inspections are necessary in addition to those recommended in 

the existing BWRVIP examination guidelines. If the applicant determines that supplemental 

inspections are not necessary, the applicant should provide adequate technical justification for the 

determination. If supplemental inspections are determined necessary for BWR vessel internals, 

the applicant should identify the components to be inspected and perform supplemental 

inspections to adequately manage loss of fracture toughness. In addition, the applicant 

should confirm the adequacy of any necessary supplemental inspections and enhancements to 

the BWR Vessel Internals Program. 

3.1.2.2.14 Loss of Preload Due to Thermal or Irradiation-Enhanced Stress Relaxation 

GALL-SLR Report AMP XI.M9 manages loss of preload due to thermal or irradiation-enhanced 

stress relaxation in BWR core plate rim holddown bolts. The issue is applicable to BWR-designed 

light water reactors that employ rim holddown bolts as the means for protecting the reactor’s core 

plate from the consequences of lateral movement. The potential for such movement, if left 

unmanaged, could impact the ability of the reactor to be brought to a safe shutdown condition 

during an anticipated transient occurrence or during a postulated design-basis accident or seismic 

event. This issue is not applicable to BWR reactor designs that use wedges as the means of 
3.1-11 

precluding lateral movement of the core plate because the wedges are fixed in place and are not 

subject to this type of aging effect and mechanism combination. 

GALL-SLR Report AMP XI.M9 indicates that the inspections in the BWRVIP topical report, “BWR 

Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines 

(BWRVIP-25),” are used to manage loss of preload due to thermal or irradiation-enhanced stress 

relaxation in BWR designs with core plate rim holddown bolts. However, in previous license 

renewal applications (LRAs), some applicants have identified that the inspection bases for 

managing loss of preload in BWRVIP-25 may not be capable of gaining access to the rim 

holddown bolts or are not sufficient to detect loss of preload on the components. For applicants 

that have identified this issue in their past LRAs, the applicants either committed to modifying the 

plant design to install wedges in the core plate designs or to submit an inspection plan, with a 

supporting core plate rim holddown bolt preload analysis for NRC approval at least 2 years prior to 

entering into the initial period of extended operation for the facility. 

If an existing NRC-approved analysis for the bolts exists in the CLB and conforms to the definition 

of a TLAA, the applicant should identify the analysis as a TLAA for the SLRA and demonstrate 

how the analysis is acceptable in accordance with either 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

Otherwise, if a new analysis will be performed to support an updated augmented inspection basis 

for the bolts for the subsequent period of extended operation, the NRC staff recommends that a 

license renewal commitment be placed in the FSAR Supplement for the applicant to submit both 

the inspection plan and the supporting loss of preload analysis to the NRC staff for approval at 

least 2 years prior to entering into the subsequent period of extended operation for the facility. If 

loss of preload in the bolts is managed with an AMP that correlates to GALL-SLR Report 

AMP XI.M9, the inspection basis in the applicable BWRVIP report is reviewed for continued 

validity, or else augmented as appropriate. 

3.1.2.2.15 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

Loss of material due to general (steel only), crevice, or pitting corrosion and cracking due to SCC 

(SS only) can occur in steel and SS piping and piping components exposed to concrete. 

Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for 

steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through 

the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, 

which can penetrate the protective oxide layer created in the high alkalinity environment, can 

reach the surface of the metal. Carbonation can reduce the pH within concrete. The rate of 

carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability. 

Concrete with low permeability also reduces the potential for the penetration of water. Adequate 

air entrainment improves the ability of the concrete to resist freezing and thawing cycles and 

therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well 

as pitting and crevice corrosion can occur due to halides present in the water that penetrates to 

the surface of the metal. 

If the following conditions are met, loss of material is not considered to be an applicable aging 

effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

(ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) 

as cited in NUREG–1557; (b) plant-specific OE indicates no degradation of the concrete that 

could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

exposed to groundwater. For SS components loss of material and cracking due to SCC are not 

considered to be applicable aging effects as long as the piping is not potentially exposed to 
3.1-12 

groundwater. Where these conditions are not met, loss of material due to general (steel only), 

crevice or pitting corrosion and cracking due to SCC (SS only) are identified as applicable aging 

effects. GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes 

an acceptable program to manage these aging effects. 

3.1.2.2.16 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

Loss of material due to pitting and crevice corrosion could occur in indoor or outdoor SS and 

nickel alloy piping, piping components, and tanks exposed to any air, condensation, or 

underground environment when the component is: (a) uninsulated; (b) insulated; (c) in the vicinity 

of insulated components; or (d) in the vicinity of potentially transportable halogens. Loss of 

material due to pitting and crevice corrosion can occur on SS and nickel alloys in environments 

containing sufficient halides (e.g., chlorides) in the presence of moisture. 

Insulated SS and nickel alloy components exposed to air, condensation, or underground 

environments are susceptible to loss of material due to pitting or crevice corrosion if the insulation 

contains certain contaminants. Leakage of fluids through mechanical connections such as bolted 

flanges and valve packing can result in contaminants leaching onto the component surface or 

the surfaces of other components below the component. For outdoor insulated SS and nickel 

alloy components, rain and changing weather conditions can result in moisture intrusion into 

the insulation. 

Plant-specific OE and the condition of SS and nickel alloy components are evaluated to determine 

if prolonged exposure to the plant-specific environments has resulted in pitting or crevice 

corrosion. Loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management for SS and nickel alloy components if (a) plant-specific OE does not reveal a history 

of loss of material due to pitting or crevice corrosion; and (b) a one-time inspection demonstrates 

that the aging effect is not occurring or is occurring so slowly that it will not affect the intended 

function of the components during the subsequent period of extended operation. The applicant 

documents the results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to 

occur as the result of a source of moisture and halides. Inspections focus on the most 

susceptible locations. 

The GALL-SLR Report recommends further evaluation of SS and nickel alloy piping and piping 

components exposed to an air, condensation, or underground environment to determine whether 

an AMP is needed to manage the aging effect of loss of material due to pitting and crevice 

corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an acceptable 

program to demonstrate that loss of material due to pitting and crevice corrosion is not occurring 

at a rate that will affect the intended function of the components. If loss of material due to pitting 

or crevice corrosion has occurred and is sufficient to potentially affect the intended function of an 

SSC, GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” 

describes an acceptable program to manage loss of material due to pitting or crevice corrosion. 

The timing of the one-time or periodic inspections is consistent with that recommended in the 

AMP selected by the applicant during the development of the SLRA. For example, one-time 

inspections would be conducted between the 50th and 60th year of operation, as recommended by 

the “detection of aging effects” program element in AMP XI.M32. 
3.1-13 

The applicant may establish that loss of material due to pitting and crevice corrosion is not an 

aging effect requiring management by demonstrating that a barrier coating isolates the component 

from aggressive environments. Acceptable barriers include tightly-adhering coatings that have 

been demonstrated to be impermeable to aqueous solutions and air that contain halides. GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” describes an acceptable program to manage the integrity of a 

barrier coating. 

3.1.2.2.17 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR). 

3.1.2.2.18 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.1.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.1.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and are based on the program elements 

of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs credited in the 

SLRA to confirm consistency with the GALL-SLR Report AMPs identified in Chapters X, “Aging 

Management Programs That May Be Used to Demonstrate Acceptability of Time-Limited 

Aging Analyses in Accordance With Under 10 CFR 54.21(c) (1)(iii)” and XI, “Aging 

Management Programs.” 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

10 CFR 54.21(a)(3) would still be met. The reviewer should then confirm that the SLRA AMP with 

all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the SLRA AMP, 

the reviewer identifies a difference between the SLRA AMP and the GALL-SLR Report AMP that 

should have been identified as an exception to the GALL-SLR Report AMP, the difference should 

be reviewed and properly dispositioned. The reviewer should document the disposition of all 

SLRA-defined exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing licensee AMP 

to be declared consistent with the GALL-SLR Report AMP to which the licensee AMP is 

compared. The reviewer is to confirm both that the enhancement, when implemented, would 

allow the existing licensee AMP to be consistent with the GALL-SLR Report AMP and that the 

applicant has a commitment in the FSAR Supplement to implement the enhancement prior to the 

subsequent period of extended operation. The reviewer should document the disposition of 

all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 
3.1-14 

3.1.2.5 Final Safety Analysis Report Supplement 

The programs and activities for managing the effects of aging for the subsequent period of 

extended operation described in the FSAR Supplement should be sufficiently comprehensive, 

such that later changes can be controlled by 10 CFR 50.59. The description should contain 

information associated with the bases for determining that aging effects will be managed during 

the subsequent period of extended operation. The description should also contain any future 

aging management activities, including enhancements and commitments, to be completed before 

the subsequent period of extended operation. Table X-01 and Table XI-01 of the GALL-SLR 

Report provide examples of the type of information to be included in the FSAR Supplement. 

Table 3.1-2 lists the programs that are applicable for this SRP-SLR subsection. 

3.1.3 Review Procedures 

For each area of review, the following review procedures are to be followed. 

3.1.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a re-review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to the GALL-SLR Report in its 

SLRA. In making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects have been addressed based on the staff’s review of industry and 

plant-specific OE. 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review requires the reviewer to confirm 

that the applicant has identified those aging effects for the reactor vessel, internals, and reactor 

coolant system components that are contained in the GALL-SLR Report as applicable to its plant. 

3.1.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Subsection 3.1.3.1 need to be applied first for all of the 

AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to which 

the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply for each of the following aging effect/aging mechanism combinations. 

3.1.3.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be TLAAs, 

as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Section 4.3 to determine whether the applicant has provided a sufficient basis for 
3.1-15 

dispositioning the TLAAs in accordance with the acceptance criteria in 10 CFR 54.21(c)(1)(i), (ii), 

or (iii). This includes staff’s review of those cumulative usage factor analyses that qualify as 

TLAAs and are based on plant-specific, stress-based calculation methods. 

3.1.3.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

1. An augmented program is recommended for the management of loss of material due to 

general, pitting, and crevice corrosion for steel PWR SG shell assembly exposed to 

secondary feedwater and steam. The existing program relies on control of water 

chemistry to mitigate corrosion and ISI to detect loss of material. The extent and 

schedule of the existing SG inspections are designed to ensure that flaws cannot attain 

a depth sufficient to threaten the integrity of the welds. However, according to NRC 

IN 90-04, the program may not be sufficient to detect pitting and crevice corrosion, if 

general and pitting corrosion of the shell is known to exist. Therefore, an augmented 

inspection is recommended to manage this aging effect. Furthermore, this issue is 

limited to Westinghouse Model 44 and 51 Steam Generators where a high-stress region 

exists at the shell to transition cone weld. Acceptance criteria are described in 

BTP RLSB-1 (Appendix A.1 of this SRP-SLR). Loss of material due to general, pitting, 

and crevice corrosion could also occur for the steel top head enclosure (without 

cladding) top head nozzles (vent, top head spray or reactor core isolation cooling 

(RCIC), and spare) exposed to reactor coolant. The existing program relies on control of 

reactor water chemistry to mitigate corrosion. However, control of water chemistry does 

not preclude loss of material due to pitting and crevice corrosion at locations of stagnant 

flow conditions. Therefore, the effectiveness of the water chemistry control program 

should be verified to ensure that corrosion is not occurring. The reviewer verifies on a 

case-by-case basis that the applicant has proposed a program that will manage loss 

of material due to general, pitting and crevice corrosion by providing enhanced 

inspection and supplemental methods to detect loss of material and ensure that the 

component-intended function will be maintained during the subsequent period of 

extended operation. 

2. Further evaluation is recommended of programs to manage the loss of material due to 

general, pitting, and crevice corrosion for the new transition cone closure weld generated 

in the steel PWR replacement recirculating steam generator transition cone shell 

exposed to secondary feedwater and steam. The existing program relies on control of 

reactor water chemistry to mitigate corrosion and on ISI to detect loss of material. The 

reviewer verifies on a case-by-case basis that the applicant has proposed an augmented 

program that will manage loss of material due to general, pitting, and crevice corrosion 

and ensure that the component-intended function will be maintained during the 

subsequent period of extended operation. 

The reviewer verifies that the applicant has described the surface condition and the 

resultant flow near the new transition cone closure weld (e.g., weld crown, ground flush, 

etc.) and how these parameters could affect the susceptibility of this weld to this aging 

effect, relative to that of the upper and lower transition welds. Based on this information, 

the reviewer verifies whether any additional aging management of the new transition weld 

is necessary. If additional aging management is necessary, the reviewer verifies whether 

the applicant has described an AMP of the new transition cone closure weld (including 

examination frequency and technique) that will be effective in managing an aging effect, 

such as the loss of material due to general, pitting, and crevice corrosion during the 

subsequent period of extended operation for the new transition cone closure weld. 
3.1-16 

3.1.3.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

1. Neutron irradiation embrittlement is a TLAA as defined in 10 CFR 54.3. TLAAs are 

required to be evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews 

the evaluation of this TLAA following the guidance in Section 4.2 of this SRP-SLR. 

2. Neutron irradiation embrittlement is a TLAA as defined in 10 CFR 54.3. TLAAs are 

required to be evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews 

the evaluation of this TLAA following the guidance in Section 4.2 of this SRP-SLR. 

Further evaluation is recommended for a reactor vessel materials surveillance program 

for the subsequent period of extended operation to monitor neutron embrittlement of the 

reactor vessel. The reactor vessel surveillance program is either a plant-specific 

surveillance program or an integrated surveillance program, depending on matters such 

as the composition of limiting materials, availability of surveillance. A neutron fluence 

monitoring program is used to monitor the neutron fluence levels that are used as the 

time-dependent inputs for those reactor vessel neutron irradiation embrittlement TLAAs 

that are the subject of the topics in SRP-SLR Section 3.1.2.2.3, Subsection 1, and 

SRP-SLR Section 4.2. 

In accordance with 10 CFR Part 50, Appendix H, an applicant must submit its proposed 

capsule withdrawal schedule for approval prior to implementation. Untested capsules 

placed in storage must be maintained for future insertion. Thus, further NRC staff 

evaluation is required for SLR. The reviewer verifies on a case-by-case basis that the 

applicant has proposed an adequate reactor vessel materials surveillance program for 

the subsequent period of extended operation. The reviewer also verifies on a 

case-by-case basis whether the applicant has proposed an acceptable neutron fluence 

monitoring AMP for the subsequent period of extended operation. Specific 

recommendations for acceptable AMPs are provided in GALL-SLR Report AMP XI.M31, 

“Reactor Vessel Surveillance,” for reactor vessel material surveillance programs and 

GALL-SLR Report AMP X.M2, “Neutron Fluence Monitoring,” for neutron fluence 

monitoring programs. 

3. Reduction in Fracture Toughness for B&W reactor internals is a TLAA as defined 

in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). The NRC staff reviews the evaluation of this TLAA following the 

guidance in Section 4.7 of this SRP-SLR consistent with the action item documented in 

the NRC staff’s safety evaluation for B&W Owners Group report number BAW-2248, 

which is included in BAW-2248A, March 2000. 

3.1.3.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

Corrosion Cracking 

1. Cracking due to SCC and IGSCC could occur in stainless steel and nickel alloy RV 

flange leak detection lines of BWR light-water reactor facilities. The reviewer 

independently verifies the sufficiency of the applicant’s evaluation of plant-specific OE. If 

the review of plant-specific OE reveals that SCC and IGSCC is not applicable, the 

reviewer verifies that GALL-SLR Report AMP XI.M32, “One-Time Inspection,” is cited for 

all applicable AMR line items. If the review of plant-specific OE reveals that SCC or 

IGSCC is applicable, the reviewer verifies that GALL-SLR Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” is cited for all applicable AMR line 

items. The reviewer should ensure that the inspection method proposed for the 
3.1-17 

inspection of the components is capable of providing indications of cracking prior to a 

loss of intended function in the lines. 

2. An augmented program is recommended to include temperature and radioactivity 

monitoring of the shell-side water and eddy current testing of tubes for the management 

of cracking due to SCC and IGSCC of the SS BWR isolation condenser components. 

The existing program relies on control of reactor water chemistry to mitigate SCC and 

IGSCC and on ASME Code Section XI ISI to detect leakage. However, the existing 

program should be augmented to detect cracking due to SCC and IGSCC. The reviewer 

reviews the applicant’s proposed program on a case-by-case basis to ensure that an 

adequate program will be in place for the management of these aging effects. 

3.1.3.2.5 Crack Growth Due to Cyclic Loading 

Further evaluation is recommended of evaluations or analyses in the CLB to manage crack 

growth due to cyclic loading in RPV shell forgings clad with SS using a high-heat-input welding 

process. Specifically, the CLB may include flaw growth evaluations of intergranular separations 

(i.e., underclad cracks) that have been identified in the RPV-to-cladding welds for the vessel. The 

evaluations apply to SA-508 Class 2 RPV forging components where the cladding was deposited 

and welded to the vessel using a high-heat-input welding process. Tor CLBs that include these 

types of evaluations, the evaluations may need to be identified as TLAAs if they are determined to 

conform to the six criteria for defining TLAAs in 10 CFR 54.3(a). The methodology for evaluating 

the underclad flaw should be consistent with the current well-established flaw evaluation 

procedure and criterion in the ASME Code Section XI. The SRP-SLR, Section 4.7 provides 

generic guidance for meeting the requirements of 10 CFR 54.21(c). The NRC staff reviews the 

evaluation of this TLAA separately following the guidance in Section 4.7 of this SRP-SLR. 

3.1.3.2.6 Cracking Due to Stress Corrosion Cracking 

1. A plant-specific AMP should be evaluated to manage cracking due to SCC in PWR SS 

bottom-mounted instrument guide tubes exposed to reactor coolant. The reviewer 

reviews the applicant’s proposed program on a case-by-case basis to ensure that an 

adequate program will be in place for the management of these aging effects. 

2. A plant-specific AMP should be evaluated to manage cracking due to SCC in CASS 

PWR Class 1 reactor coolant system piping and piping components exposed to reactor 

coolant that do not meet the carbon and ferrite content guidelines of NUREG–0313. The 

reviewer reviews the applicant’s proposed program on a case-by-case basis to ensure 

that an adequate program will be in place for the management of these aging effects. 

3. Cracking due to SCC could occur in SS or nickel alloy RV flange leak detection lines of 

PWR light-water reactor facilities. The reviewer independently verifies the sufficiency of 

the applicant’s evaluation of plant-specific OE. If the review of plant-specific OE reveals 

that SCC is not applicable, the reviewer verifies that GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” is cited for all applicable AMR line items. If the review of 

plant-specific OE reveals that SCC is applicable, the reviewer verifies that GALL-SLR 

Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” is cited 

for all applicable AMR line items. The reviewer should ensure that the inspection 

method proposed for the inspection of the components is capable of providing 

indications of cracking prior to a loss of intended function in the lines. 
3.1-18 

3.1.3.2.7 Cracking Due to Cyclic Loading 

An augmented program for the management of cracking due to cyclic loading in steel and SS 

BWR isolation condenser components is recommended. The existing program relies on 

ASME Code Section XI ISI for detection. However, the inspection requirements should be 

augmented to detect cracking due to cyclic loading. An augmented program to include 

temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes 

is recommended to ensure that the component’s intended function will be maintained during the 

subsequent period of extended operation. The reviewer verifies on a case-by-case basis that the 

applicant has proposed an augmented program that will detect cracking and ensure that 

the component-intended function will be maintained during the subsequent period of 

extended operation. 

3.1.3.2.8 Loss of Material Due to Erosion 

Further evaluation of a plant-specific AMP is recommended for the management of loss of 

material due to erosion of steel steam generator feedwater impingement plates and supports 

exposed to secondary feedwater. The reviewer reviews the applicant’s proposed program on a 

case-by-case basis to ensure that an adequate program will be in place for the management of 

these aging effects. 

3.1.3.2.9 Aging Management of PWR Reactor Vessel Internals (Applicable to Subsequent 

License Renewal Periods Only) 

EPRI TR–1022863, “Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guidelines (MRP-227-A)” (ADAMS Accession Nos. ML12017A191 

through ML12017A197 and ML12017A199), provides the industry’s current aging management 

recommendations for the RVI components that are included in the design of a PWR facility, based 

on an analysis of plant operation for 60 years. In this report, the EPRI MRP identified that the 

following aging mechanisms may be applicable to the design of the RVI components in these 

types of facilities: (a) SCC, (b) IASCC, (c) fatigue, (d) wear, (e) neutron irradiation embrittlement, 

(f) thermal aging embrittlement, (g) void swelling and irradiation growth, or (h) thermal or 

irradiation-enhanced stress relaxation or irradiation enhanced creep. The methodology in 

MRP-227-A was approved by the NRC in a safety evaluation dated December 16, 2011 (ADAMS 

Accession No. ML11308A770), which includes those plant-specific applicant/licensee action items 

that a licensee or applicant applying the MRP-227-A report would need to address and resolve 

and apply to its licensing basis. 

The assessments of RVI components in the MRP-227-A report and the MRP-defined background 

reports for MRP-227-A have not been updated based on an assessment of aging effects over an 

80-year operating period. 

If a plant-specific AMP is proposed for the RVI components, the reviewer evaluates the adequacy 

of the applicant’s AMP on a case-by-case basis against the criteria for plant-specific AMP 

program elements defined in Sections A.1.2.3.1 through A.1.2.3.10 of SRP-SLR Appendix A.1. 

The reviewer verifies that the applicant has defined both the type of performance monitoring, 

condition monitoring, preventative monitoring, or mitigative monitoring AMP that will be used for 

aging management of the RVI components and the specific program element criteria for the AMP 

that will be used to manage age-related effects in the RVI components during the subsequent 

period of extended operation. 
3.1-19 

If a PWR applicant for SLR proposes to use GALL-SLR Report AMP XI.M16A, “PWR Vessel 

Internals,” as the basis for aging management, the staff reviews the program elements of the AMP 

against the program element criteria defined in AMP XI.M16A. The staff verifies that the proposed 

program includes a gap analysis that provides the identification and justification of: 

 Components that screen in for additional aging effects or mechanisms when assessed for 

aging through the end of the subsequent period of extended operation 

 Components that previously screened in for an aging effect or mechanism and the severity 

of that aging effect or mechanism could significantly increase during the subsequent 

period of extended operation 

 Changes to the existing MRP-227-A program characteristics or criteria, including but not 

limited to changes in inspection categories, inspection criteria, or primary-to-expansion 

component criteria and relationships 

The staff evaluates the adequacy and justification of the gap analysis, specifically: 

 The gap analysis methodology 

 The components that screened in for additional aging effects or mechanisms when 

assessed for aging through the end of the subsequent period of extended operation 

 The components for which a previously screened in aging effect or mechanism has been 

identified as potentially more severe during the subsequent period of extended operation 

 Proposed changes to the aging management program characteristics or criteria identified 

in the SLRA 

For those RVI components that screened in for additional aging effects or mechanisms, the 

staff also confirms that the applicant has included and justified appropriate AMR line items for 

the components. 

Otherwise an applicant may use an NRC-approved generic methodology such as an approved 

revision of MRP-227 that considers an operating period of 80 years. In this case, the staff reviews 

any responses to action items on the aging management methods that may be identified in the 

NRC approval of the generic methodology. 

3.1.3.2.10 Loss of Material Due to Wear 

1. Loss of material due to wear can occur in PWR CRD head penetration nozzles due to 

the interactions between the nozzle and the thermal sleeve centering pads of the nozzle. 

The applicant should perform a further evaluation to confirm the adequacy of a 

plant-specific AMP or analysis (with any necessary inspections) for management of the 

aging effect. The reviewer confirms that the applicant’s plant-specific AMP for managing 

this aging effect meets the acceptance criteria that are described in BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). Alternatively, the reviewer confirms that loss of 

material due to wear does not affect the intended function(s) of CRD head penetration 

nozzles, consistent with the CLB, if the applicant relies on an analysis for aging 

management. The reviewer also confirms whether inspections are necessary to ensure 

the adequacy of the analysis. 
3.1-20 

2. Loss of material due to wear can occur in the thermal sleeves of PWR CRD head 

penetration nozzles due to the interactions between the nozzle and the thermal sleeve. 

The applicant should perform a further evaluation to confirm the adequacy of a 

plant-specific AMP for management of the aging effect. The reviewer confirms that the 

applicant’s plant-specific AMP for managing this aging effect meets the acceptance 

criteria that are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR).

3.1.3.2.11 Cracking Due to Primary Water Stress Corrosion Cracking 

1. A plant-specific AMP should be evaluated, along with the primary water chemistry and 

steam generator programs, to manage cracking due to PWSCC in nickel alloy divider 

plate assemblies. For divider plate assemblies fabricated of Alloy 690 and Alloy 690 

type welding materials, a plant-specific AMP is not necessary. For divider plate 

assemblies made of Alloy 600 or Alloy 600 type welding materials, the reviewer verifies 

that the applicant has an adequate basis for concluding that the analyses performed by 

the industry (EPRI 3002002850) assessing the significance of divider plate cracking are 

applicable and bounding for the conditions at its unit. If the industry’s analyses are not 

bounding, the reviewer evaluates the applicant’s plant-specific AMP on a case-by-case 

basis to ensure that an adequate plant-specific AMP will be in place for the management 

of this aging effect or the reviewer reviews the applicant’s rationale (e.g., a more detailed 

plant-specific evaluation than performed by the industry) for why such a plant-specific 

AMP is not necessary. 

2. A plant-specific AMP should be evaluated, along with the primary water chemistry and 

steam generator programs, to manage cracking due to PWSCC in nickel alloy steam 

generator tube-to-tubesheet welds exposed to reactor coolant. The reviewer verifies the 

combination of materials of construction of the steam generator tubes and tubesheet 

cladding and the classification of the tube-to-tubesheet weld (i.e., whether it is part of the 

reactor coolant pressure boundary). If the combination and classification require a 

plant-specific AMP, the reviewer reviews the applicant’s proposed program on a caseby-case basis to ensure adequate management of this aging effect. Alternatively, the 

reviewer evaluates applicant’s rationale for why a plant-specific AMP is not necessary. 

3.1.3.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking 

GALL-SLR Report AMP XI.M9, “BWR Vessel Internals,” manages aging degradation of nickel 

alloy and SS, including associated welds, which are used in BWR vessel internal components. 

When exposed to the BWR vessel environment, these materials can experience cracking due to 

IASCC. The existing BWRVIP examination guidelines are mainly based on aging evaluation of 

BWR vessel internals for operation up to 60 years. However, increases in neutron fluence during 

the SLR term may need to be assessed for supplemental inspections of BWR vessel internals to 

adequately manage cracking due to IASCC. 

The applicant should perform an evaluation to determine whether supplemental inspections are 

necessary in addition to the existing BWRVIP examination guidelines to adequately manage 

cracking due to IASCC for BWR vessel internals. This evaluation for supplemental inspections is 

based on neutron fluence and cracking susceptibility (i.e., applied stress, operating temperature, 

and environmental conditions). The NRC staff reviews the applicant’s evaluation to ensure that 

adequate supplemental inspections are identified and included in the applicant’s BWR Vessel 

Internals Program as necessary for aging management of cracking due to IASCC. In addition, 
3.1-21 

any necessary enhancements to the BWR Vessel Internals Program should be reviewed for 

adequate justification. 

3.1.3.2.13 Loss of Fracture Toughness Due to Neutron Irradiation or Thermal Aging 

Embrittlement 

GALL-SLR Report AMP XI.M9 manages aging degradation of nickel alloy and SS, including 

associated welds, which are used in BWR vessel internal components. When exposed to the 

BWR vessel environment, these materials can experience loss of fracture toughness due to 

neutron irradiation embrittlement. In addition, CASS, precipitation-hardened (PH) martensitic SS 

(e.g., 15-5 and 17-4 PH steel) and martensitic SS (e.g., 403, 410, 431 steel) can experience loss 

of fracture toughness due to neutron irradiation or thermal aging embrittlement. 

The applicant should perform an evaluation to determine whether supplemental inspections are 

necessary in addition to the existing BWRVIP examination guidelines to adequately manage loss 

of fracture toughness for BWR vessel internals. This evaluation for supplemental inspections is 

based on neutron fluence, thermal aging susceptibility, fracture toughness, and cracking 

susceptibility (i.e., applied stress, operating temperature, and environmental conditions). The 

NRC staff reviews the applicant’s evaluation to ensure that adequate supplemental inspections 

are identified and included in the applicant’s BWR Vessel Internals Program as necessary for 

aging management of loss of fracture toughness. In addition, any necessary enhancements to 

the BWR Vessel Internals Program should be reviewed for adequate justification.

3.1.3.2.14 Loss of Preload Due to Thermal or Irradiation-Enhanced Stress Relaxation 

GALL-SLR Report AMP XI.M9 of the GALL-SLR Report, “BWR Vessel Internals,” manages loss 

of preload due to thermal or irradiation-enhanced stress relaxation in BWR core plate rim 

holddown bolts. The issue is applicable to BWR light water reactors that employ rim holddown 

bolts as the means for protecting the reactor’s core plate from the consequences of lateral 

movement. The potential for such movement, if left unmanaged, could impact the ability of the 

reactor to be brought into a safe shutdown condition during an anticipated transient occurrence or 

during a postulated design-basis accident or seismic event. This issue is not applicable to BWR 

reactor designs that use wedges as the means of precluding lateral movement of the core plate 

because the wedges are fixed in place and are not subject to this type of aging effect and 

mechanism combination. 

GALL-SLR Report AMP XI.M9 indicates that the inspections in BWRVIP topical report, “BWR 

Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines 

(BWRVIP-25),” is used to manage loss of preload due to thermal or irradiation-enhanced stress 

relaxation in BWR designs with core plate rim holddown bolts. However, in initial LRAs, some 

applicants have identified that the inspection bases for managing loss of preload in BWRVIP-25 

may not be capable of gaining access to the rim holddown bolts or are not sufficient to detect loss 

of preload on the components. For applicants that have identified this issue in their past LRAs, 

the applicants have committed to modifying the plant design to install wedges in the core plate 

designs or to submitting an inspection plan, with a supporting core plate rim holddown bolt preload 

analysis for NRC approval at least 2 years prior to entering the subsequent period of extended 

operation for the facility. 

For SLRAs that apply to BWRs with core plate rim holddown bolts, the reviewer assesses whether 

the SLRA has included an enhanced augmented inspection basis for plants’ core plate rim 

holddown bolts as applicable, and has justified the augmented inspection basis that will be applied 
3.1-22 

to the components, as appropriate. If an existing NRC-approved analysis for the bolts exists in 

the CLB and conforms to the definition of a TLAA, the reviewer assesses whether the applicant 

has identified the analysis as a TLAA for the SLRA and has demonstrated why the analysis is 

acceptable in accordance with either 10 CFR 54.21(c)(1)(i), (ii), or (iii). Otherwise, if a new 

analysis will be performed to support an updated 80-year augmented inspection basis for the bolts 

for the subsequent period of extended operation, the NRC staff reviews the applicant’s 

augmented inspection and evaluation basis to determine whether the FSAR Supplement for the 

SLRA has included a license commitment to submit both the inspection plan and the supporting 

loss of preload analysis to the NRC staff at least 2 years prior to entering into the subsequent 

period of extended operation for the facility. 

3.1.3.2.15 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

For steel piping and piping components exposed to concrete, if the following conditions are met, 

loss of material is not considered to be an applicable aging effect for steel: (a) 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; (b) plant-specific OE indicates no 

degradation of the concrete that could lead to penetration of water to the metal surface; and 

(c) the piping is not potentially exposed to groundwater. For SS piping and piping components, 

loss of material and cracking due to SCC are not considered to be applicable aging effects as long 

as the piping is not potentially exposed to groundwater. Where these conditions are not met, loss 

of material due to general (steel only), crevice, or pitting corrosion, and cracking due to SCC 

(SS only) are identified as applicable aging effects. GALL-SLR Report AMP XI.M41, “Buried 

and Underground Piping and Tanks,” describes an acceptable program to manage these 

aging effects. 

The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-tocement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

reviewer should evaluate plant-specific OE to determine whether concrete degradation sufficient 

to allow water intrusion has occurred. 

3.1.3.2.16 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

and crevice corrosion of SS and nickel alloy piping and piping components exposed to any air, 

condensation, or underground environment when the component is: (a) uninsulated; 

(b) insulated; (c) in the vicinity of insulated components where the presence of sufficient 

halides (e.g., chlorides) and moisture is possible; or (d) in the vicinity of potentially 

transportable halogens. 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals loss of material due to pitting or crevice corrosion in 

SS and nickel alloys, the reviewer determines whether an adequate program is credited to 

manage the aging effect. If there is no related plant-specific OE, the reviewer verifies that 

AMP XI.M32, “One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the applicant could categorize the 

indoor air locations as those where leakage could impinge on the SS component’s surface 
3.1-23 

(e.g., leakage from mechanical connections) and those where there is not a potential for leakage. 

When the applicant chooses to conduct its OE search in this manner, the reviewer is to also 

confirm that the applicant has adequately addressed the potential for the periodic introduction of 

either moisture or halides from secondary sources. Secondary sources of moisture or halides 

should be considered for all environments including indoor conditioned air. Typical secondary 

sources of moisture or halides include: leakage from mechanical connections, leakage into 

vaults, and insulation containing halides. Grouping of environments consistent with that described 

in the detection of aging effects program element of GALL-SLR Report AMP XI.M38, “Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.1.3.2.17 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMPs for SLR should contain the elements of corrective actions, the confirmation 

process, and administrative controls. Safety-related components are covered by 10 CFR Part 50, 

Appendix B, which is adequate to address these program elements. However, Appendix B does 

not apply to nonsafety-related components that are subject to an AMR for SLR. Nevertheless, the 

applicant has the option to expand the scope of its 10 CFR Part 50, Appendix B program to 

include these components and address the associated program elements. If the applicant 

chooses this option, the reviewer verifies that the applicant has documented such a commitment 

in the FSAR Supplement. If the applicant chooses alternative means, the branch responsible for 

quality assurance (QA) should be requested to review the applicant’s proposal on a case-by-case 

basis. 

3.1.3.2.18 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to 

ensure that the AMPs are effective to manage the aging effects for which they are created. The 

AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined 

through the evaluation of OE that the effects of aging may not be adequately managed. 

Additional information is in Appendix A.4, “Operating Experience for Aging Management 

Programs.” 

In addition, the reviewer confirms that the applicant has provided an appropriate summary 

description of these activities in the FSAR Supplement.

3.1.3.3 Aging Managing Review Results Not Consistent With or Not Addressed in the Generic 

Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging effects, 

listed the appropriate combination of materials and environments, and AMPs that will adequately 

manage the aging effects. The AMP credited by the applicant could be an AMP that is described 
3.1-24 

and evaluated in the GALL-SLR Report or a plant-specific program. Review procedures are 

described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.1.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP, with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the reactor vessel, internals, and reactor coolant system are summarized in 

Table 3.1-1 of this SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in 

the GALL-SLR Report, Chapter IV, presenting detailed information summarized by this row. 

3.1.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in its FSAR Supplement information for 

aging management of the reactor vessel, internals, and reactor coolant system. Table 3.1-2 lists 

the AMPs that are applicable for this SRP-SLR subsection. The reviewer also confirms that the 

applicant has provided information for Subsection 3.1.3.3, “Aging Management Review Results 

Not Consistent With or Not Addressed in the Generic Aging Lessons Learned for Subsequent 

License Renewal Report.” 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

3.1.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 
3.1-25 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has demonstrated that the aging effects associated with the reactor 

vessel, internals, and reactor coolant system components will be adequately 

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

CLB for the subsequent period of extended operation, as required by 

10 CFR 54.21(a)(3). 

The NRC staff also reviewed the applicable FSAR Supplement program 

summaries and concludes that they adequately describe the AMPs credited for 

managing aging of the reactor vessel, internals and reactor coolant system, as 

required by 10 CFR 54.21(d). 

3.1.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.1.6 References 

1. NEI. NEI 97-06, “Steam Generator Program Guidelines.” Revision 2. Agencywide 

Documents Access and Management System (ADAMS) Accession No. ML052710007. 

Washington, DC: Nuclear Energy Institute. September 2005. 

2. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. ADAMS Accession No. 

ML051860406. Washington, DC: Nuclear Energy Institute. June 2005. 

3. NRC. Information Notice 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth 

Welds in Steam Generators.” ADAMS Accession No. ML031470418. Washington, DC: 

U.S. Nuclear Regulatory Commission. January 26, 1990. 

4. NRC. NUREG–0313, “Technical Report on Material Selection and Processing Guidelines 

for BWR Coolant Pressure Boundary Piping.” Revision 2. ADAMS Accession No. 

ML031470422. Washington, DC: U.S. Nuclear Regulatory Commission. January 1988. 

5. EPRI. EPRI 1013706, “PWR Steam Generator Examination Guidelines. Revision 7. 

Palo Alto, California: Electric Power Research Institute. October 2007. 

6. NRC. Regulatory Guide 1.121, “Bases for Plugging Degraded PWR Steam Generator 

Tubes (for Comment).” ADAMS Accession No.ML003739366. Washington, DC: 

U.S. Nuclear Regulatory Commission. May 1976. 

7. NRC. Generic Letter 95-05, “Voltage-Based Repair Criteria for Westinghouse Steam 

Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking.” ADAMS 

Accession No. ML041680635. Washington, DC: U.S. Nuclear Regulatory Commission. 

August 3, 1995. 
3.1-26 

8. NRC. Information Notice 90-10, “Primary Water Stress Corrosion Cracking (PWSCC) of 

Inconel 600.” ADAMS Accession No. ML053070392. Washington, DC: U.S. Nuclear 

Regulatory Commission. February 23, 1990. 

9. NRC. Information Notice 90-30, “Ultrasonic Inspection Techniques for Dissimilar Metal 

Welds.” ADAMS Accession No. ML031470652. Washington, DC: U.S. Nuclear 

Regulatory Commission. May 1, 1990. 

10. NRC. Generic Letter 89-08, “Erosion/Corrosion-Induced Pipe Wall Thinning.” ADAMS 

Accession No. ML082320534. Washington, DC: U.S. Nuclear Regulatory Commission. 

May 2, 1989. 

11. NRC. Information Notice 96-11, “Ingress of Demineralizer Resins Increase Potential for 

Stress Corrosion Cracking of Control Rod Drive Mechanism Penetrations.” ADAMS 

Accession No. ML031060264. Washington, DC: U.S. Nuclear Regulatory Commission. 

February 14, 1996. 

12. EPRI. BWRVIP–190 (EPRI 1016579), “BWR Vessel and Internals Project: BWR Water 

Chemistry Guidelines.” Palo Alto, California: Electric Power Research Institute. 

October 2008 

13. EPRI. EPRI NP–5769, “Degradation and Failure of Bolting in Nuclear Power Plants.” 

Volumes 1 and 2. Palo Alto, California: Electric Power Research Institute. April 1988. 

14. EPRI. EPRI TR–1014986, “PWR Primary Water Chemistry Guidelines.” Revision 7. 

Volumes 1 and 2. Palo Alto, California: Electric Power Research Institute. April 2014. 

15. NRC. Generic Letter 88-01, “NRC Position on IGSCC in BWR Austenitic Stainless Steel 

Piping.” ADAMS Accession No. ML031130463. Washington, DC: U.S. Nuclear 

Regulatory Commission. January 25, 1988. 

16. NRC. Generic Letter 97-01, “Degradation of Control Rod Drive Mechanism Nozzle and 

Other Vessel Closure Head Penetrations.” ADAMS Accession No. ML993550383. 

Washington, DC: U.S. Nuclear Regulatory Commission. April 1, 1997. 

17. NRC. Information Notice 97-46, “Unisolable Crack in High-Pressure Injection Piping.” 

Washington, DC: U.S. Nuclear Regulatory Commission. July 9, 1997. 

18. NRC. Regulatory Guide 1.99, “Radiation Embrittlement of Reactor Vessel Materials.” 

Washington, DC: U.S. Nuclear Regulatory Commission. May 1988. 

19. NRC. Information Notice 2013-20, “Steam Generator Channel Head and Tubesheet 

Degradation.” ADAMS Accession No. ML13204A143. Washington, DC: U.S. Nuclear 

Regulatory Commission. October 3, 2013. 

20. NRC. NUREG–0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle 

Cracking.” ADAMS Accession No. ML031600712. Washington, DC: U.S. Nuclear 

Regulatory Commission. November 1980. 
3.1-27 

21. NRC. NUREG–1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or 

Failure in Nuclear Power Plants.” ADAMS Accession No. ML031430208. 

Washington, DC: U.S. Nuclear Regulatory Commission. June 1990. 

22. EPRI. EPRI TR–104213, “Bolted Joint Maintenance & Application Guide, Electric Power 

Research Institute.” Palo Alto, California: Electric Power Research Institute. 

December 1995. 

23. Dave Modeen. NEI Letter (December 11) to Gus Lainas, “Responses to NRC Requests 

for Additional Information (RAIs) on GL 97-01.” Washington, DC: Nuclear Energy 

Institute. 1998. 

24. EPRI. EPRI TR–1016555, “PWR Secondary Water Chemistry Guidelines–Revision 7.” 

Palo Alto, California: Electric Power Research Institute. February 2009. 

25. NRC. Information Notice 91-19, “Steam Generator Feedwater Distribution Piping 

Damage.” Washington, DC: U.S. Nuclear Regulatory Commission. March 12, 1991. 

26. EPRI. EPRI TR–1022863, “Materials Reliability Program: Pressurized Water Reactor 

Internals Inspection and Evaluation Guidelines (MRP-227-A).” Palo Alto, California: 

Electric Power Research Institute. December 2011. 

27. Entergy Operations, Inc. “Demonstration of the Management of Aging Effects for the 

Reactor Vessel Internals.” Topical Report BAW-2248A. Russellville, Arkansas: Entergy 

Operations, Inc. March 2000. 

28. EPRI. EPRI TR–1014982, “Divider Plate Cracking in Steam Generators - Results of 

Phase 1: Analysis of Primary Water Stress Corrosion Cracking and Mechanical Fatigue in 

the Alloy 600 Stub Runner to Divider Plate Weld Material.” Palo Alto, California: Electric 

Power Research Institute. June 2007. 

29. Dominion Nuclear Connecticut, Inc. Letter (July 13) to NRC, Dominion Nuclear 

Connecticut, Inc. Millstone Power Station Unit 3 Results of the Reactor Pressure 

Vessel Head Inspections Required by NRC Order EA-03-009. 2007. 

30. Southern Company. Letter (June 21) to the NRC, Vogtle Electric Generating Plant - Unit 2 

Results of Reactor Pressure Vessel Head Inspections Required by First Revised Order 

EA-03-009. Atlanta, Georgia: Southern Company. 2007. 

31. EPRI. EPRI 3002002850, “Steam Generator Management Program: Investigation of 

Crack Initiation and Propagation in the Steam Generator Channel Head Assembly.” 

Palo Alto, California: Electric Power Research Institute, October 2014. 

32. EPRI. EPRI 1020988, “Steam Generator Management Program: Phase II Divider Plate 

Cracking Engineering Study.” Palo Alto, California: Electric Power Research Institute. 

November 2010. 

33. EPRI. EPRI 1016552, “Divider Plate Cracking in Steam Generators: Results of Phase II: 

Evaluation of the Impact of a Cracked Divider Plate on LOCA and Non-LOCA Analyses.” 

Palo Alto, California: Electric Power Research Institute. November 2008. 
3.1-28 

34. EPRI. Presentation, “NRC/Industry Meeting Regarding Tube-to-Tubesheet Weld and 

Divider Plate Cracking Report.” Palo Alto, California: Electric Power Research Institute. 

July 30, 2015. 

35. ACI. ACI Standard 318-95, “Building Code Requirements for Reinforced Concrete and 

Commentary.” Farmington Hills, Michigan: American Concrete Institute. 1995. 

36. ACI. ACI Standard. 349-85, “Code Requirements for Nuclear Safety-Related Concrete 

Structures.” Farmington Hills, Michigan: American Concrete Institute. 1985. 

37. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License Renewal.” 

Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 
3.1-29 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 001 BWR/PWR Steel reactor vessel 

closure flange assembly components exposed to air-indoor uncontrolled 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A1.RP-201 IV.A2.RP-54 

M 002 PWR Nickel alloy tubes and 

sleeves exposed to reactor coolant, secondary feedwater/steam 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.D1.R-46 IV.D2.R-46 

M 003 BWR/PWR Stainless steel, nickel alloy 

reactor vessel internal components exposed to reactor coolant, neutron flux 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.B1.R-53 IV.B2.RP-303 IV.B3.RP-339 IV.B4.R-53 

M 004 BWR/PWR Steel pressure vessel 

support skirt and attachment welds 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A1.R-70 IV.A2.R-70 

M 005 PWR Steel, stainless steel, steel 

(with stainless steel or nickel alloy cladding) steam generator components, pressurizer relief tank components, piping components, bolting 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C2.R-13 IV.C2.R-18 IV.D1.R-33 IV.D2.R-33 

M 006 BWR Stainless steel, steel (with 

or without nickel alloy or stainless steel cladding), nickel alloy reactor coolant pressure boundary components: piping, piping components; other pressure retaining components exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C1.R-220 
3.1-30 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 007 BWR Stainless steel, steel (with 

or without nickel alloy or stainless steel cladding), nickel alloy reactor vessel components: nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads and welds exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A1.R-04 

M 008 PWR Stainless steel, steel (with 

or without nickel alloy or stainless steel cladding), nickel alloy steam generator components exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.D1.R-221 IV.D2.R-222 

M 009 PWR Stainless steel, steel (with 

or without nickel alloy or stainless steel cladding), nickel alloy reactor coolant pressure boundary piping, piping components; other pressure retaining components exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C2.R-223 

M 010 PWR Steel (with or without nickel 

alloy or stainless steel cladding), stainless steel, or nickel alloy reactor vessel components: nozzles; penetrations; pressure housings; safe ends; thermal sleeves; vessel shells, heads and welds exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A2.R-219 
3.1-31 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 011 BWR/PWR Steel or stainless steel 

pump and valve closure bolting exposed to high temperatures and thermal cycles 

Cumulative fatigue damage: cracking due to fatigue, cyclic loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C1.RP-44 IV.C2.RP-44 

E 012 PWR Steel steam generator 

components: upper and lower shells, transition cone; new transition cone closure weld exposed to secondary feedwater or steam 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Sections 3.1.2.2.2.1 and 3.1.2.2.2.2) 

IV.D1.RP-368 

M 013 BWR/PWR Steel (with or without 

stainless steel or nickel alloy cladding) reactor vessel beltline shell, nozzle, and weld components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement 

TLAA, SRP-SLR Section 4.2 "Reactor Pressure Vessel Neutron Embrittlement" 

Yes (SRP-SLR Section 3.1.2.2.3.1) 

IV.A1.R-62 IV.A2.R-84 

M 014 BWR/PWR Steel (with or without 

cladding) reactor vessel beltline shell, nozzle, and weld components; exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement 

AMP XI.M31, "Reactor Vessel Material Surveillance," and AMP X.M2, "Neutron Fluence Monitoring" 

Yes (SRP-SLR Section 3.1.2.2.3.2) 

IV.A1.RP-227 IV.A2.RP-229 

M 015 PWR Stainless steel Babcock & 

Wilcox (including CASS, martensitic SS, and PH SS) and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux 

Reduction in fracture toughness due to neutron irradiation 

TLAA, SRP-SLR Section 4.7 "Other Plant-Specific TLAAs" 

Yes (SRP-SLR Section 3.1.2.2.3.3) 

IV.B4.RP-376 
3.1-32 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 016 BWR Stainless steel or nickel 

alloy reactor vessel top head enclosure flange leakage detection line exposed to air-indoor uncontrolled, reactor coolant leakage 

Cracking due to SCC, IGSCC 

AMP XI.M32, "One-Time Inspection," or AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.1.2.2.4.1) 

IV.A1.R-61a IV.A1.R-61b 

E 017 BWR Stainless steel isolation 

condenser components exposed to reactor coolant 

Cracking due to SCC, IGSCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.4.2) 

IV.C1.R-15 

E 018 PWR Reactor vessel shell 

fabricated of SA508-Cl 2 forgings clad with stainless steel using a high-heatinput welding process exposed to reactor coolant 

Crack growth due to cyclic loading 

TLAA, SRP-SLR Section 4.7 "Other Plant-Specific TLAAs" 

Yes (SRP-SLR Section 3.1.2.2.5) 

IV.A2.R-85 

M 019 PWR Stainless steel reactor 

vessel bottom-mounted instrument guide tubes (external to reactor vessel) exposed to reactor coolant 

Cracking due to SCC Plant-specific aging 

management program 

Yes (SRP-SLR Section 3.1.2.2.6.1) 

IV.A2.RP-154 

E 020 PWR Cast austenitic stainless 

steel Class 1 piping, piping components exposed to reactor coolant 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry" and plant specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.6.2) 

IV.C2.R-05 

E 021 BWR Steel and stainless steel 

isolation condenser components exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

Yes (SRP-SLR Section 3.1.2.2.7) 

IV.C1.R-225 
3.1-33 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

E 022 PWR Steel steam generator 

feedwater impingement plate and support exposed to secondary feedwater 

Loss of material due to erosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.8) 

IV.D1.R-39 

M 025 PWR 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 

Cracking due to primary water SCC 

AMP XI.M2, "Water Chemistry," and AMP XI.M19, "Steam Generators." In addition, a plantspecific program is to be evaluated. 

Yes (SRP-SLR Sections 3.1.2.2.11.1 and 3.1.2.2.11.2) 

IV.D1.RP-367 IV.D1.RP-385 IV.D2.RP-185 

M 028 PWR "Existing Programs" 

components: Stainless steel, nickel alloy Westinghouse control rod guide tube support pins, and Combustion Engineering thermal shield positioning pins; Zircaloy-4 Combustion Engineering incore instrumentation thimble tubes exposed to reactor coolant and neutron flux 

Loss of material due to wear; cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-356 IV.B3.RP-357 IV.B3.RP-400 

M 029 BWR Nickel alloy core shroud 

and core plate access hole cover (welded covers) exposed to reactor coolant 

Cracking due to SCC, IGSCC, irradiationassisted SCC 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12) 

IV.B1.R-94 

E 030 BWR Stainless steel, nickel alloy 

penetration: drain line exposed to reactor coolant 

Cracking due to SCC, IGSCC, cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" (SCC, IGSCC mechanisms only) 

No IV.A1.RP-371 
3.1-34 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 031 BWR Steel and stainless steel 

isolation condenser components exposed to reactor coolant 

Loss of material due to general (steel only), pitting, crevice corrosion, wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C1.RP-39 

M 032 PWR Stainless steel, nickel 

alloy, or CASS reactor vessel internals, core support structure (not already referenced as ASME Section XI Examination Category BN-3 core support structure components in MRP-227-A), exposed to reactor coolant and neutron flux 

Cracking, loss of material due to wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.B2.RP-382 

IV.B3.RP-382 IV.B4.RP-382 

E 033 PWR Stainless steel, steel with 

stainless steel cladding Class 1 reactor coolant pressure boundary components exposed to reactor coolant 

Cracking due to SCC AMP XI.M1, "ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.R-09 

IV.C2.R-217 IV.C2.RP-344 IV.D1.RP-232 

E 034 PWR 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) 

Cracking due to SCC AMP XI.M1, "ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.RP-231 
3.1-35 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

E 035 PWR Stainless steel, steel with 

stainless steel cladding reactor coolant system cold leg, hot leg, surge line, and spray line piping and fittings exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-56 

M 036 PWR Steel, stainless steel 

pressurizer integral support exposed to any environment 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-19 

E 037 PWR Steel reactor vessel flange Loss of material due to 

wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A2.R-87 

M 038 BWR/PWR Cast austenitic stainless 

steel Class 1 valve bodies and bonnets exposed to reactor coolant >250 °C (>482 °F) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C1.R-08 

IV.C2.R-08 

M 039 BWR/PWR Stainless steel, steel (with 

or without nickel alloy or stainless steel cladding), nickel alloy Class 1 piping, fittings and branch connections < NPS 4 exposed to reactor coolant 

Cracking due to SCC (for stainless steel or nickel alloy surfaces exposed to reactor coolant only), IGSCC (for stainless steel or nickel alloy surfaces exposed to reactor coolant only), or thermal, mechanical, or vibratory loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," AMP XI.M2, "Water Chemistry," and XI.M35, "ASME Code Class 1 Small-Bore Piping" 

No IV.C1.RP-230 

IV.C2.RP-235 

M 040 PWR Steel with stainless steel or 

nickel alloy cladding; or stainless steel pressurizer components exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-58 
3.1-36 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

E 040a PWR Nickel alloy core support 

pads; core guide lugs exposed to reactor coolant 

Cracking due to primary water SCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-57 

M 041 BWR Nickel alloy core shroud 

and core plate access hole cover (mechanical covers) exposed to reactor coolant 

Cracking due to SCC, IGSCC, irradiationassisted SCC 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12) 

IV.B1.R-95 

E 042 PWR Steel with stainless steel or 

nickel alloy cladding; stainless steel primary side components; steam generator upper and lower heads, and tube sheet welds; pressurizer components exposed to reactor coolant 

Cracking due to SCC, primary water SCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.R-25 

IV.D2.RP-47 

E 043 BWR Stainless steel and nickel 

alloy reactor vessel internals exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.B1.RP-26 

M 044 PWR Steel steam generator 

secondary manway and handhole cover seating surfaces exposed to treated water, steam 

Loss of material due to erosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.D1.R-31 

IV.D2.R-31 
3.1-37 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

 045 PWR Nickel alloy, steel with 

nickel alloy cladding reactor coolant pressure boundary components exposed to reactor coolant 

Cracking due to primary water SCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry," and, for nickel-alloy, AMP XI.M11B, "Cracking of NickelAlloy Components and Loss of Material Due to Boric Acid-induced Corrosion in RCPB Components (PWRs Only)" 

No IV.A2.R-90 

IV.A2.RP-186 IV.A2.RP-59 IV.C2.RP-156 IV.C2.RP-159 IV.C2.RP-37 IV.D1.RP-36 IV.D2.RP-36 

M 046 PWR Stainless steel, nickel alloy 

control rod drive head penetration pressure housings, reactor vessel nozzles, nozzle safe ends and welds exposed to reactor coolant 

Cracking due to SCC, primary water SCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry," and, for nickel-alloy, AMP XI.M11B, "Cracking of NickelAlloy Components and Loss of Material Due to Boric Acid-induced corrosion in RCPB Components (PWRs Only)" 

No IV.A2.RP-234 
3.1-38 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

 047 PWR Stainless steel, nickel alloy 

control rod drive head penetration pressure housing exposed to reactor coolant 

Cracking due to SCC, primary water SCC 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-55 

 048 PWR 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 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion," and AMP XI.M11B, "Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid- Induced Corrosion in RCPB Components (PWRs Only)" 

No IV.A2.RP-379 

IV.C2.RP-380 

M 049 PWR Steel reactor vessel, 

piping, piping components in the reactor coolant pressure boundary of PWRs, and applicable exterior attachments, or steel steam generators in PWRs: external surfaces or closure bolting exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No IV.A2.R-17 

IV.C2.R-17 IV.C2.RP-167 IV.D1.R-17 IV.D2.R-17 

M 050 BWR/PWR Cast austenitic stainless 

steel Class 1 piping, piping components (including pump casings and control rod drive pressure housings) exposed to reactor coolant >250 °F (>482 °C) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)" 

No IV.A2.R-77 

IV.C1.R-52 IV.C2.R-52 
3.1-39 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 051a PWR Stainless steel, nickel alloy 

Babcock & Wilcox reactor internal "Primary" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B4.RP-241 IV.B4.RP-241a IV.B4.RP-242a IV.B4.RP-247 IV.B4.RP-247a IV.B4.RP-248 IV.B4.RP-248a IV.B4.RP-249a IV.B4.RP-252a IV.B4.RP-256 IV.B4.RP-256a IV.B4.RP-258a IV.B4.RP-259a IV.B4.RP-261 IV.B4.RP-400 

M 051b PWR Stainless steel, nickel alloy 

Babcock & Wilcox reactor internal "Expansion" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue, overload 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B4.RP-244 IV.B4.RP-244a IV.B4.RP-245 IV.B4.RP-245a IV.B4.RP-246 IV.B4.RP-246a IV.B4.RP-254 IV.B4.RP-254a IV.B4.RP-260a IV.B4.RP-262 IV.B4.RP-352 IV.B4.RP-250a 
3.1-40 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 052a PWR Stainless steel, nickel alloy 

Combustion Engineering reactor internal "Primary" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-312 IV.B3.RP-314 IV.B3.RP-322 IV.B3.RP-324 IV.B3.RP-326a IV.B3.RP-327 IV.B3.RP-328 IV.B3.RP-342 IV.B3.RP-358 IV.B3.RP-362a IV.B3.RP-363 IV.B3.RP-338 IV.B3.RP-343 

M 052b PWR Stainless steel, nickel alloy 

Combustion Engineering reactor internal "Expansion" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-313 IV.B3.RP-316 IV.B3.RP-323 IV.B3.RP-325 IV.B3.RP-329 IV.B3.RP-330 IV.B3.RP-333 IV.B3.RP-335 IV.B3.RP-362c 

M 052c PWR Stainless steel, nickel alloy 

Combustion Engineering reactor internal "Existing Programs" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-320 IV.B3.RP-334 

M 053a PWR Stainless steel, nickel alloy 

Westinghouse reactor internal "Primary" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-270a IV.B2.RP-271 IV.B2.RP-275 IV.B2.RP-276 IV.B2.RP-280 IV.B2.RP-298 IV.B2.RP-302 IV.B2.RP-387 
3.1-41 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 053b PWR Stainless steel 

Westinghouse reactor internal "Expansion" components exposed to reactor coolant and neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-273 IV.B2.RP-278 IV.B2.RP-286 IV.B2.RP-291 IV.B2.RP-291a IV.B2.RP-291b IV.B2.RP-293 IV.B2.RP-294 IV.B2.RP-387a 

M 053c PWR Stainless steel, nickel alloy 

Westinghouse reactor internal "Existing Programs" components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, fatigue 

AMP XI.M16A, "PWR Vessel Internals," and AMP XI.M2, "Water Chemistry" (for SCC mechanisms only) 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-289 IV.B2.RP-301 IV.B2.RP-346 IV.B2.RP-399 IV.B2.RP-355 

M 054 PWR Stainless steel bottom 

mounted instrument system flux thimble tubes (with or without chrome plating) exposed to reactor coolant and neutron flux 

Loss of material due to wear 

AMP XI.M37, "Flux Thimble Tube Inspection" 

No IV.B2.RP-284 

M 055a PWR Stainless steel, nickel alloy 

Babcock and Wilcox reactor internal "No Additional Measures" components exposed to reactor coolant, neutron flux 

No additional aging management for reactor internal "No Additional Measures" components unless required by ASME Section XI, Examination Category B-N-3 or relevant operating experience exists 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B4.RP-236 
3.1-42 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 055b PWR Stainless steel, nickel alloy 

Combustion Engineering reactor internal "No Additional Measures" components exposed to reactor coolant, neutron flux 

No additional aging management for reactor internal "No Additional Measures" components unless required by ASME Section XI, Examination Category B-N-3 or relevant operating experience exists 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-306 

M 055c PWR Stainless steel, nickel alloy 

Westinghouse reactor internal "No Additional Measures" components exposed to reactor coolant, neutron flux 

No additional aging management for reactor internal "No Additional Measures" components unless required by ASME Section XI, Examination Category B-N-3 or relevant operating experience exists 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-265 

M 056a PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) or nickel alloy Combustion Engineering reactor internal "Primary" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-315 IV.B3.RP-318 IV.B3.RP-359 IV.B3.RP-360 IV.B3.RP-362 IV.B3.RP-364 IV.B3.RP-366 IV.B3.RP-365 IV.B3.RP-326 
3.1-43 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 056b PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) Combustion Engineering "Expansion" reactor internal components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-317 IV.B3.RP-331 IV.B3.RP-359a IV.B3.RP-361 IV.B3.RP-362b IV.B3.R-455 

M 056c PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) or nickel alloy Combustion Engineering reactor internal "Existing Programs" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B3.RP-319 IV.B3.RP-332 IV.B3.RP-334a IV.B3.RP-336 
3.1-44 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 058a PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS), nickel alloy Babcock & Wilcox reactor internal "Primary" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; or changes in dimensions due to void swelling or distortion; or loss of preload due to wear; or loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B4.RP-240 IV.B4.RP-240a IV.B4.RP-242 IV.B4.RP-247b IV.B4.RP-248b IV.B4.RP-249 IV.B4.RP-251 IV.B4.RP-251a IV.B4.RP-252 IV.B4.RP-256b IV.B4.RP-258 IV.B4.RP-259 IV.B4.RP-401 

M 058b PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS), nickel alloy Babcock & Wilcox reactor internal "Expansion" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; or changes in dimensions due to void swelling, or distortion; or loss of preload due to thermal and irradiation-enhanced stress relaxation, or creep; or loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B4.RP-245b IV.B4.RP-246b IV.B4.RP-254b IV.B4.RP-260 IV.B4.RP-243 IV.B4.RP-243a IV.B4.RP-250 
3.1-45 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 059a PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) or nickel alloy Westinghouse reactor internal "Primary" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-270 IV.B2.RP-272 IV.B2.RP-296 IV.B2.RP-297 IV.B2.RP-302a IV.B2.RP-354 IV.B2.RP-388 IV.B2.RP-300 

M 059b PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) Westinghouse reactor internal "Expansion" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-274 IV.B2.RP-278a IV.B2.RP-287 IV.B2.RP-290 IV.B2.RP-290a IV.B2.RP-290b IV.B2.RP-292 IV.B2.RP-295 IV.B2.RP-388a 
3.1-46 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 059c PWR Stainless steel (SS, 

including CASS, PH SS or martensitic SS) or nickel alloy Westinghouse reactor internal "Existing Programs" components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement and for CASS, martensitic SS, and PH SS due to thermal aging embrittlement; changes in dimensions due to void swelling, distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation, creep; loss of material due to wear 

AMP XI.M16A, "PWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.RP-285 IV.B2.RP-288 IV.B2.RP-299 IV.B2.RP-345 

E 060 BWR Steel piping, piping 

components exposed to reactor coolant 

Wall thinning due to flowaccelerated corrosion AMP XI.M17, "Flow-Accelerated 

Corrosion" 

No IV.C1.R-23 

 061 PWR Steel steam generator 

steam nozzle and safe end, feedwater nozzle and safe end, AFW nozzles and safe ends exposed to secondary feedwater/steam 

Wall thinning due to flowaccelerated corrosion AMP XI.M17, "Flow-Accelerated 

Corrosion" 

No IV.D1.R-37 

IV.D2.R-38 

M 062 BWR/PWR High-strength steel, 

stainless steel closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air-indoor uncontrolled 

Cracking due to SCC AMP XI.M18, 

"Bolting Integrity" 

No IV.A2.R-78 

IV.C1.R-11 IV.C2.R-11 IV.D1.R-10 IV.D2.R-10 

M 063 BWR Steel or stainless steel 

closure bolting exposed to air – indoor uncontrolled 

Loss of material due to general (steel only), pitting, crevice corrosion, wear 

AMP XI.M18, "Bolting Integrity" 

No IV.C1.RP-42 
3.1-47 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 064 PWR Steel or stainless steel 

closure bolting exposed to air – indoor uncontrolled 

Loss of material due to general (steel only), pitting, crevice corrosion, wear 

AMP XI.M18, "Bolting Integrity" 

No IV.C2.RP-166 

IV.D1.RP-166 IV.D2.RP-166 

M 065 PWR Stainless steel control rod 

drive head penetration flange bolting exposed to air-indoor uncontrolled 

Loss of material due to wear 

AMP XI.M18, "Bolting Integrity" 

No IV.A2.R-79 

M 066 PWR Steel, stainless steel 

closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air-indoor uncontrolled 

Loss of preload due to thermal effects, gasket creep, self-loosening 

AMP XI.M18, "Bolting Integrity" 

No IV.A2.R-80 

IV.C2.R-12 

M 067 BWR/PWR Steel or stainless steel 

closure bolting exposed to air – indoor uncontrolled (external) 

Loss of preload due to thermal effects, gasket creep, self-loosening 

AMP XI.M18, "Bolting Integrity" 

No IV.C1.RP-43 

IV.D1.RP-46 IV.D2.RP-46 

 068 PWR Nickel alloy steam 

generator tubes exposed to secondary feedwater or steam 

Changes in dimension ("denting") due to corrosion of carbon steel tube support plate 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-43 

IV.D2.R-226 

M 069 PWR Nickel alloy steam 

generator tubes and sleeves exposed to secondary feedwater or steam 

Cracking due to outer diameter SCC, intergranular attack 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-47 

IV.D2.R-47 

 070 PWR Nickel alloy steam 

generator tubes, repair sleeves, and tube plugs exposed to reactor coolant 

Cracking due to primary water SCC 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-40 

IV.D1.R-44 IV.D2.R-40 IV.D2.R-44 
3.1-48 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

 071 PWR Steel, chrome plated steel, 

stainless steel, nickel alloy steam generator U-bend supports including antivibration bars exposed to secondary feedwater or steam 

Cracking due to SCC or other mechanism(s); loss of material due general (steel only), pitting, crevice corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-226 

IV.D1.RP-384 

E 072 PWR Steel steam generator tube 

support plate, tube bundle wrapper, supports and mounting hardware exposed to secondary feedwater or steam 

Loss of material due to general, pitting, crevice corrosion, erosion, ligament cracking due to corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" (corrosion based aging effects and mechanisms only) 

No IV.D1.R-42 

IV.D1.RP-161 IV.D2.R-42 IV.D2.RP-162 

 073 PWR Nickel alloy steam 

generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater or steam 

Loss of material due to wastage, pitting corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-50 

 074 PWR Steel steam generator 

upper assembly and separators including feedwater inlet ring and support exposed to secondary feedwater or steam 

Wall thinning due to flowaccelerated corrosion AMP XI.M19, "Steam Generators," and 

AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-49 

 075 PWR Steel steam generator tube 

support lattice bars exposed to secondary feedwater or steam 

Wall thinning due to flowaccelerated corrosion, general corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-48 

M 076 PWR Steel, chrome plated steel, 

stainless steel, nickel alloy steam generator U-bend supports including antivibration bars exposed to secondary feedwater or steam 

Loss of material due to wear, fretting 

AMP XI.M19, "Steam Generators" 

No IV.D1.RP-225 
3.1-49 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

 077 PWR Nickel alloy steam 

generator tubes and sleeves exposed to secondary feedwater or steam 

Loss of material due to wear, fretting 

AMP XI.M19, "Steam Generators" 

No IV.D1.RP-233 

IV.D2.RP-233 

 078 PWR Nickel alloy steam 

generator components such as, secondary side nozzles (vent, drain, and instrumentation) exposed to secondary feedwater or steam 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection," or AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." 

No IV.D2.R-36 

 079 BWR Stainless steel; steel with 

nickel alloy or stainless steel cladding; and nickel alloy reactor coolant pressure boundary components exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C1.RP-158 

 080 PWR 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) 

Cracking due to SCC AMP XI.M2, 

"Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP-383 

 081 PWR Stainless steel pressurizer 

spray head exposed to reactor coolant 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP-41 

 082 PWR Nickel alloy pressurizer 

spray head exposed to reactor coolant 

Cracking due to SCC, primary water SCC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP-40 
3.1-50 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

 083 PWR Steel steam generator 

shell assembly exposed to secondary feedwater or steam 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.D1.RP-372 

IV.D2.RP-153 

M 084 BWR Steel top head enclosure 

(without cladding): top head, top head nozzles (vent, top head spray, RCIC, spare) exposed to reactor coolant 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.A1.RP-50 

 085 BWR 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 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.A1.RP-157 

 086 PWR Stainless steel steam 

generator primary side divider plate exposed to reactor coolant 

Cracking due to SCC AMP XI.M2, 

"Water Chemistry" 

No IV.D1.RP-17 

 087 PWR Stainless steel, nickel alloy 

PWR reactor internal components exposed to reactor coolant, neutron flux 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry" 

No IV.B2.RP-24 

IV.B3.RP-24 IV.B4.RP-24 

 088 PWR Stainless steel; steel with 

nickel alloy or stainless steel cladding; and nickel alloy reactor coolant pressure boundary components exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-28 

IV.C2.RP-23 
3.1-51 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 089 PWR Steel piping, piping 

components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No IV.C2.RP-221 

M 090 PWR Copper alloy piping, piping 

components exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No IV.C2.RP-222 

M 091 BWR Steel (including highstrength steel) reactor 

vessel closure flange assembly components (including flanges, nut, studs, and washers) exposed to air-indoor uncontrolled 

Cracking due to SCC; loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M3, "Reactor Head Closure Stud Bolting" 

No IV.A1.RP-165 

IV.A1.RP-51 

M 092 PWR Steel (including highstrength steel) reactor 

vessel closure flange assembly components (including flanges, nut, studs, and washers) exposed to air-indoor uncontrolled 

Cracking due to SCC, IGSCC; loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M3, "Reactor Head Closure Stud Bolting" 

No IV.A2.RP-52 

IV.A2.RP-53 

M 093 PWR Copper alloy >15% Zn or 

>8% Al piping, piping components exposed to closed-cycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No IV.C2.RP-12 

M 094 BWR Stainless steel and nickel 

alloy vessel shell attachment welds exposed to reactor coolant 

Cracking due to SCC, IGSCC, cyclic loading 

AMP XI.M4, "BWR Vessel ID Attachment Welds," and AMP XI.M2, "Water Chemistry" (SCC, IGSCC mechanisms only) 

No IV.A1.R-64 
3.1-52 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 095 BWR Steel (with or without 

stainless steel or nickel alloy cladding) feedwater nozzles exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A1.R-65 

M 096 BWR Steel (with or without 

stainless steel cladding) control rod drive return line nozzles and their nozzleto-vessel welds exposed to reactor coolant in BWR-3, BWR-4, BWR-5, and BWR-6 designs 

Cracking due to SCC, IGSCC, cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A1.R-66 

M 097 BWR Stainless steel and nickel 

alloy piping, piping components greater than or equal to 4 NPS; nozzle safe ends and associated welds; control rod drive return line nozzle cap and associated cap-to-nozzle weld or cap-to-safe end weld in BWR-3, BWR 4, BWR 5, and BWR-6 designs 

Cracking due to SCC, IGSCC 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

No IV.A1.R-412 

IV.C1.R-20 IV.C1.R-21 

E 098 BWR Stainless steel, nickel alloy 

penetrations: instrumentation and standby liquid control exposed to reactor coolant 

Cracking due to SCC, IGSCC, cyclic loading 

AMP XI.M8, "BWR Penetrations," and AMP XI.M2, "Water Chemistry" (SCC, IGSCC mechanisms only) 

No IV.A1.RP-369 
3.1-53 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 099 BWR Stainless steel (including 

cast austenitic stainless steel; PH martensitic stainless steel; martensitic stainless steel); nickel alloy (including X-750 alloy) reactor internal components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to thermal aging, neutron irradiation embrittlement 

AMP XI.M9, "BWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.13) 

IV.B1.RP-182 IV.B1.RP-200 IV.B1.RP-219 IV.B1.RP-220 IV.B1.R-416 IV.B1.R-417 IV.B1.R-419 

 100 BWR Stainless steel reactor 

vessel internals components (jet pump wedge surface) exposed to reactor coolant 

Loss of material due to wear 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.RP-377 

M 101 BWR Stainless steel steam 

dryers exposed to reactor coolant 

Cracking due to flowinduced vibration, SCC, IGSCC; loss of material due to wear 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.RP-155 

 102 BWR Stainless steel fuel 

supports and control rod drive assemblies control rod drive housing exposed to reactor coolant 

Cracking due to SCC, IGSCC 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

No IV.B1.R-104 

M 103 BWR Stainless steel, nickel alloy 

reactor internal components exposed to reactor coolant and neutron flux 

Cracking due to SCC, IGSCC, irradiationassisted SCC 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12) 

IV.B1.R-422 IV.B1.R-100 IV.B1.R-105 IV.B1.R-92 IV.B1.R-93 IV.B1.R-96 IV.B1.R-97 IV.B1.R-98 IV.B1.R-99 

M 104 BWR Nickel alloy reactor vessel 

internal components exposed to reactor coolant and neutron flux 

Cracking due to IGSCC AMP XI.M9, "BWR 

Vessel Internals," and AMP XI.M2, "Water Chemistry" 

No IV.B1.RP-381 
3.1-54 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 105 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.1.2.2.15) 

IV.E.RP-353 

M 106 BWR/PWR Nickel alloy piping, piping 

components exposed to air with borated water leakage 

None None No IV.E.RP-378 

M 107 BWR/PWR Stainless steel piping, 

piping components exposed to gas, air with borated water leakage 

None None No IV.E.RP-05 

IV.E.RP-07 

M 110 BWR Metallic piping, piping 

components exposed to reactor coolant 

Wall thinning due to erosion 

AMP XI.M17, "FlowAccelerated Corrosion" No IV.C1.R-406 

N 111 PWR Nickel alloy steam 

generator tubes exposed to secondary feedwater or steam 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M19, "Steam Generators" 

No IV.D1.R-407 

IV.D2.R-407 

N 113 BWR Steel reactor vessel 

external attachments exposed to indoor, uncontrolled air 

Loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A1.R-409 
3.1-55 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 114 BWR/PWR Reactor coolant system 

components defined as ASME Section XI Code Class components (ASME Code Class 1 reactor coolant pressure boundary components or core support structure components, or ASME Class 2 or 3 components - including ASME defined appurtenances, component supports, and associated pressure boundary welds, or components subject to plant-specific equivalent classifications for these ASME code classes) 

Cracking due to SCC, IGSCC (stainless steel, nickel alloy components only), cyclic loading; loss of material due to general corrosion (steel only), pitting corrosion, crevice corrosion, wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" (water chemistryrelated or corrosionrelated aging effect mechanisms only) 

No IV.E.R-444 

N 115 BWR/PWR Stainless steel piping, 

piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.1.2.2.15) 

IV.E.RP-06 

N 116 PWR Nickel alloy control rod 

drive penetration nozzles exposed to reactor coolant 

Loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.10.1) 

IV.A2.R-413 

N 117 PWR Stainless steel, nickel alloy 

control rod drive penetration nozzle thermal sleeves exposed to reactor coolant 

Loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.10.2) 

IV.A2.R-414 

N 118 PWR Stainless steel, nickel alloy 

PWR reactor vessel internal components exposed to reactor coolant, neutron flux 

Cracking due to SCC, irradiation-assisted SCC, cyclic loading, fatigue 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.R-423 IV.B3.R-423 IV.B4.R-423 
3.1-56 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 119 PWR Stainless steel, nickel alloy 

PWR reactor vessel internal components exposed to reactor coolant, neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement or thermal aging embrittlement; changes in dimensions due to void swelling or distortion; loss of preload due to thermal and irradiation-enhanced stress relaxation or creep; loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.R-424 IV.B3.R-424 IV.B4.R-424 

N 120 BWR Stainless steel core plate 

rim holddown bolts exposed to reactor coolant and neutron flux 

Loss of preload due to thermal or irradiationenhanced stress relaxation 

AMP XI.M9, "BWR Vessel Internals," and TLAA SRP-SLR 4.7 "Other Plant-Specific TLAAs" [if an analysis is performed as part of the aging management basis and conforms to the definition of a TLAA in 10 CFR 54.3(a)] 

Yes (SRP-SLR Section 3.1.2.2.14) 

IV.B1.R-420 

N 121 BWR Stainless steel jet pump 

assembly holddown beam bolts exposed to reactor coolant and neutron flux 

Loss of preload due to thermal or irradiationenhanced stress relaxation 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.R-421 

D 122 N 124 BWR/PWR Steel piping, piping 

components exposed to air-indoor uncontrolled, airoutdoor, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No IV.C1.R-431 

IV.C2.R-431 

N 125 PWR Nickel alloy steam 

generator tubes at support plate locations exposed to secondary feedwater or steam 

Cracking due to flowinduced vibration, highcycle fatigue AMP XI.M19, "Steam Generators" No IV.D1.R-437 IV.D2.R-442 
3.1-57 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 127 PWR Steel (with stainless steel 

or nickel alloy cladding) steam generator heads and tubesheets exposed to reactor coolant 

Loss of material due to boric acid corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M19, "Steam Generators" 

No IV.D1.R-436 

IV.D2.R-440 

N 128 BWR Stainless steel, nickel alloy 

nozzles safe ends and welds: high pressure core spray; low pressure core spray; recirculating water, low pressure coolant injection or RHR injection mode exposed to reactor coolant 

Cracking due to SCC, IGSCC 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

No IV.A1.R-68 

N 129 BWR Steel and stainless steel 

piping, piping components exposed to reactor coolant: welded connections between the re-routed control rod drive return line and the inlet piping system that delivers return line flow to the reactor pressure vessel exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C1.R-432 

D 130 N 133 BWR/PWR Steel components exposed 

to treated water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "One-Time Inspection" 

No IV.A1.R-448 

IV.C1.R-448 

N 134 BWR/PWR Non-metallic thermal 

insulation exposed to air, condensation 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No IV.A1.R-450 

IV.A2.R-450 IV.C1.R-450 IV.C2.R-450 IV.D1.R-450 IV.D2.R-450 

D 135 
3.1-58 

Table 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System 

Evaluated in Chapter IV of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 136 BWR/PWR Stainless steel, nickel alloy 

piping, piping components exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "OneTime Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.1.2.2.16) 

IV.C1.R-452a IV.C1.R-452b IV.C1.R-452c IV.C1.R-452d IV.C2.R-452a IV.C2.R-452b IV.C2.R-452c IV.C2.R-452d 

N 137 BWR/PWR Copper alloy piping, piping 

components exposed to air, condensation, gas 

None None No IV.E.R-453 

N 139 PWR Stainless steel, nickel alloy 

reactor vessel top head enclosure flange leakage detection line exposed to air-indoor uncontrolled, reactor coolant leakage 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," or AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.1.2.2.6.3) 

IV.A2.R-74a IV.A2.R-74b 
3.1-59 

Table 3.1-2 AMPs and Additional Guidance Appendices Recommended for 

Aging Management of Reactor Vessel, Internals, and Reactor 

Coolant System 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP X.M1 Fatigue Monitoring 

AMP X.M2 Neutron Fluence Monitoring 

AMP XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD 

AMP XI.M2 Water Chemistry 

AMP XI.M3 Reactor Head Closure Stud Bolting 

AMP XI.M4 BWR Vessel ID Attachment Welds 

AMP XI.M5 Deleted 

AMP XI.M6 Deleted 

AMP XI.M7 BWR Stress Corrosion Cracking 

AMP XI.M8 BWR Penetrations 

AMP XI.M9 BWR Vessel Internals 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M11B Cracking of Nickel-Alloy Components and Loss of Material 

Due to Boric Acid-induced Corrosion in Reactor Coolant 

Pressure Boundary Components (PWRs Only) 

AMP XI.M12 Thermal Aging of Cast Austenitic Stainless Steel (CASS) 

AMP XI.M16A PWR Vessel Internals 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M19 Steam Generators 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M31 Reactor Vessel Material Surveillance 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M35 ASME Code Class 1 Small Bore-Piping 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M37 Flux Thimble Tube Inspection 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M42 Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 

3.2-1 

3.2 Aging Management of Engineered Safety Features 

Review Responsibilities 

Primary— The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.2.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management programs (AMPs) of the engineered safety features. For a recent vintage plant, the 

information related to the engineered safety features is contained in Chapter 6, “Engineered 

Safety Features,” of the plant’s Final Safety Analysis Report (FSAR), consistent with the 

“Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants” 

(NUREG–0800). The engineered safety features contained in this review plan section are 

generally consistent with those contained in NUREG–0800 except for the refueling water, control 

room habitability, and residual heat removal systems. For older plants, the location of applicable 

information is plant-specific because an older plant’s FSAR may have predated NUREG–0800. 

The engineered safety features consist of containment spray, standby gas treatment [boiling water 

reactor (BWR)], containment isolation components, and emergency core cooling systems. 

The responsible review organization is to review the following subsequent license renewal 

application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 1.2: 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 AMR results not consistent with or not addressed in the GALL-SLR Report 

AMPs 

 Consistent with the GALL-SLR Report AMPs 

 Plant-specific AMPs 

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.2.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commission’s (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 
3.2-2 

3.2.2.1 AMR Results Consistent With the Generic Aging Lessons Learned for Subsequent 

License Renewal Report 

The AMR and the AMPs applicable to the engineered safety features are described and evaluated 

in Chapter V of the GALL-SLR Report. 

The applicant’s SLRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

consistent with the GALL-SLR Report AMR item to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

capable of managing the effects of aging as adequately as the AMP recommended by the 

GALL-SLR Report. 

3.2.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria defined in Subsection 3.2.2.1 need to be applied first for all of the 

AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR item 

to which the SLRA AMR item is compared identifies that “further evaluation is recommended,” 

then additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.2-1, comparing the “Further Evaluation 

Recommended” and the “GALL-SLR Item” column, for the AMR items that reference the 

following subsections. 

3.2.2.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be time-limited 

aging analyses (TLAAs), as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). This TLAA is addressed separately in Section 4.3, 

“Metal Fatigue,” or Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses,” of this 

SRP-SLR. For plant-specific cumulative usage factor calculations that are based on stress-based 

input methods, the methods are to be appropriately defined and discussed in the applicable 

TLAAs. 

3.2.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

Loss of material due to pitting and crevice corrosion could occur in indoor or outdoor stainless 

steel (SS) and nickel alloy piping, piping components, and tanks exposed to any air, 

condensation, or underground environment when the component is: (a) uninsulated; 

(b) insulated; (c) in the vicinity of insulated components; or (d) in the vicinity of potentially 

transportable halogens. Loss of material due to pitting and crevice corrosion can occur on SS 

and nickel alloys in environments containing sufficient halides (e.g., chlorides) in the presence 

of moisture. 

Insulated SS and nickel alloy components exposed to air, condensation, or underground 

environments are susceptible to loss of material due to pitting or crevice corrosion if the insulation 

contains certain contaminants. Leakage of fluids through mechanical connections such as bolted 
3.2-3 

flanges and valve packing can result in contaminants leaching onto the component surface or the 

surfaces of other components below the component. For outdoor insulated SS and nickel alloy 

components, rain and changing weather conditions can result in moisture intrusion into 

the insulation. 

Plant-specific operating experience (OE) and the condition of SS and nickel alloy components are 

evaluated to determine if prolonged exposure to the plant-specific environments has resulted in 

pitting or crevice corrosion. Loss of material due to pitting and crevice corrosion is not an aging 

effect requiring management for SS and nickel alloy components if (a) plant-specific OE does not 

reveal a history of loss of material due to pitting or crevice corrosion, and (b) a one-time inspection 

demonstrates that the aging effect is not occurring or is occurring so slowly that it will not affect 

the intended function of the components during the subsequent period of extended operation. 

The applicant documents the results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to 

occur as the result of a source of moisture and halides. Inspections focus on the most 

susceptible locations. 

The GALL-SLR Report recommends further evaluation of SS and nickel alloy piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. The GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that loss of material due to pitting and crevice corrosion is not 

occurring at a rate that affects the intended function of the components. If loss of material due to 

pitting or crevice corrosion has occurred and is sufficient to potentially affect the intended function 

of systems, structures, and components (SSCs), the following AMPs describe acceptable 

programs to manage loss of material due to pitting or crevice corrosion: (a) the GALL-SLR Report 

AMP XI.M29, “Outdoor and Large Atmospheric Metallic Storage Tanks,” for tanks; (b) the 

GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” for 

external surfaces of piping and piping components; (c) the GALL-SLR Report AMP XI.M41, 

“Buried and Underground Piping and Tanks,” for underground piping, piping components and 

tanks; and (d) the GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” for internal surfaces of components that are not 

included in other AMPs. The timing of the one-time or periodic inspections is consistent with that 

recommended in the AMP selected by the applicant during the development of the SLRA. For 

example, a one-time inspection would be conducted between the 50th and 60th year of operation, 

as recommended by the “detection of aging effects” program element in AMP XI.M32. 

The applicant may establish that loss of material due to pitting and crevice corrosion is not an 

aging effect requiring management by demonstrating that a barrier coating isolates the component 

from aggressive environments. Acceptable barriers include tightly-adhering coatings that have 

been demonstrated to be impermeable to aqueous solutions and air that contain halides. GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” describes an acceptable program to manage the integrity of a 

barrier coating. 
3.2-4 

3.2.2.2.3 Loss of Material Due to General Corrosion and Flow Blockage Due to Fouling 

Loss of material due to general corrosion (as applicable) and flow blockage due to fouling for all 

materials can occur in the spray nozzles and flow orifices in the drywell and suppression chamber 

spray system exposed to air-indoor uncontrolled. This aging effect and mechanism will apply 

since the carbon steel piping upstream of the spray nozzles and flow orifices is occasionally 

wetted, even though the majority of the time this system is in standby. The wetting and drying of 

these components can accelerate corrosion in the system and lead to flow blockage from an 

accumulation of corrosion products. Aging effects sufficient to result in a loss of intended function 

are not anticipated if: (a) the applicant identifies those portions of the system that are normally dry 

but subject to periodic wetting; (b) plant-specific procedures exist to drain the normally dry 

portions that have been wetted during normal plant operation or inadvertently; (c) the 

plant-specific configuration of the drains and piping allow sufficient draining to empty the normally 

dry pipe; (d) plant-specific OE has not revealed loss of material or flow blockage due to fouling; 

and (e) a one-time inspection is conducted to verify that loss of material or flow blockage due to 

fouling has not occurred. The GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes 

an acceptable program to conduct the one-time inspections. The GALL-SLR Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” describes an 

acceptable program to manage loss of material due to general corrosion and flow blockage due to 

fouling when the above conditions are not met. 

3.2.2.2.4 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

Cracking due to stress corrosion cracking (SCC) could occur in indoor or outdoor SS piping, 

piping components, and tanks exposed to any air, condensation, or underground environment 

when the component is: (a) uninsulated; (b) insulated; (c) in the vicinity of insulated components, 

or (d) in the vicinity of potentially transportable halogens. Cracking can occur in environments 

containing sufficient halides (e.g., chlorides) in the presence of moisture. 

Insulated SS components exposed to indoor air, outdoor air, condensation, or underground 

environments are susceptible to SCC if the insulation contains certain contaminants. Leakage of 

fluids through bolted connections (e.g., flanges, valve packing) can result in contaminants present 

in the insulation leaching onto the component surface or the surfaces of other components below 

the component. For outdoor insulated SS components, rain and changing weather conditions can 

result in moisture intrusion into the insulation. 

Plant-specific OE and the condition of SS components are evaluated to determine if prolonged 

exposure to the plant-specific environments has resulted in SCC. SCC in SS components is not 

an aging effect requiring management if (a) plant-specific OE does not reveal a history of SCC 

and (b) a one-time inspection demonstrates that the aging effect is not occurring. 

In the environment of air-indoor controlled, SCC is only expected to occur as the result of a source 

of moisture and halides. Inspections focus on the most susceptible locations. The applicant 

documents the results of the plant-specific OE review in the SLRA. 

The GALL-SLR Report recommends further evaluation of SS piping, piping components, and 

tanks exposed to an air, condensation, or underground environment to determine whether an 

AMP is needed to manage the aging effect of SCC. The GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” describes an acceptable program to demonstrate that SCC is not 

occurring. If SCC is applicable, the following AMPs describe acceptable programs to manage 

loss of material due to SCC: (a) the GALL-SLR Report AMP XI.M29, “Outdoor and Large 
3.2-5 

Atmospheric Metallic Storage Tanks,” for tanks; (b) the GALL-SLR Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” for external surfaces of piping and piping 

components; (c) the GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and 

Tanks,” for underground piping, piping components and tanks; and (d) the GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” 

for internal surfaces of components that are not included in other AMPs. The timing of the 

one-time or periodic inspections is consistent with that recommended in the AMP selected by the 

applicant during the development of the SLRA. For example, one-time inspections would be 

conducted between the 50th and 60th year of operation, as recommended by the “detection of 

aging effects” program element in AMP XI.M32. 

The applicant may establish that SCC is not an aging effect requiring management for all 

components, by demonstrating that a barrier coating isolates the component from aggressive 

environments. Acceptable barriers include tightly-adhering coatings that have been demonstrated 

to be impermeable to aqueous solutions and air that contain halides. The GALL-SLR Report AMP 

XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 

and Tanks,” describes an acceptable program to manage the integrity of a barrier coating. 

3.2.2.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in Branch Technical Position (BTP) IQMB-1 (Appendix A.2 of 

this SRP-SLR). 

3.2.2.2.6 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.2.2.2.7 Loss of Material Due to Recurring Internal Corrosion 

Recurring internal corrosion can result in the need to augment AMPs beyond the 

recommendations in the GALL-SLR Report. During the search of plant-specific OE conducted 

during the SLRA development, recurring internal corrosion can be identified by the number of 

occurrences of aging effects and the extent of degradation at each localized corrosion site. This 

further evaluation item is applicable if the search of plant-specific OE reveals repetitive 

occurrences. The criteria for recurrence is (a) a 10-year search of plant-specific OE reveals the 

aging effect has occurred in three or more refueling outage cycles; or (b) a 5-year search of 

plant-specific OE reveals the aging effect has occurred in two or more refueling outage cycles and 

resulted in the component either not meeting plant-specific acceptance criteria or experiencing a 

reduction in wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The GALL-SLR Report recommends that the GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” be evaluated for inclusion of 

augmented requirements to ensure the adequate management of any recurring aging effect(s). 

Alternatively, a plant-specific AMP may be proposed. Potential augmented requirements include: 

alternative examination methods (e.g., volumetric versus external visual), augmented inspections 

(e.g., a greater number of locations, additional locations based on risk insights based on 

susceptibility to aging effect and consequences of failure, a greater frequency of inspections), and 

additional trending parameters and decision points where increased inspections would 

be implemented. 
3.2-6 

The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

recurring aging effect before affecting the ability of a component to perform its intended function, 

(b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

parameters will be trended as well as the decision points where increased inspections would be 

implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

change), (d) how inspections of components that are not easily accessed (i.e., buried, 

underground) will be conducted, and (e) how leaks in any involved buried or underground 

components will be identified. 

Plant-specific OE examples should be evaluated to determine if the chosen AMP should be 

augmented even if the thresholds for significance of aging effect or frequency of occurrence of 

aging effect have not been exceeded. For example, during a 10-year search of plant-specific OE, 

two instances of a 360 degree 30 percent wall loss occurred at copper alloy to steel joints. 

Neither the significance of the aging effect nor the frequency of occurrence of aging effect 

threshold has been exceeded. Nevertheless, the OE should be evaluated to determine if the 

AMP that is proposed to manage the aging effect is sufficient (e.g., method of inspection, 

frequency of inspection, number of inspections) to provide reasonable assurance that the current 

licensing basis (CLB) intended functions of the component will be met throughout the subsequent 

period of extended operation. While recurring internal corrosion is not as likely in other 

environments as raw water and waste water (e.g., treated water), the aging effect should be 

addressed in a similar manner. 

3.2.2.2.8 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

SCC is a form of environmentally assisted cracking which is known to occur in high and moderate 

strength aluminum alloys. The three conditions necessary for SCC to occur in a component are a 

sustained tensile stress, aggressive environment, and material with a susceptible microstructure. 

Cracking due to SCC can be mitigated by eliminating one of the three necessary conditions. For 

the purposes of subsequent license renewal (SLR), acceptance criteria for this further evaluation 

are being provided for demonstrating that the specific material is not susceptible to SCC or an 

aggressive environment is not present. Cracking due to SCC is an aging effect requiring 

management unless it is demonstrated by the applicant that one of the two necessary conditions 

discussed below is absent. 

Susceptible Material: If the material is not susceptible to SCC, then cracking is not an aging effect 

requiring management. The microstructure of an aluminum alloy, of which alloy composition is 

only one factor, is what determines if the alloy is susceptible to SCC. Therefore, determining 

susceptibility based on alloy composition alone is not adequate to conclude whether a particular 

material is susceptible to SCC. The temper, condition, and product form of the alloy is considered 

when assessing if a material is susceptible to SCC. Aluminum alloys that are susceptible to 

SCC include: 

 2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

 5xxx series alloys with a magnesium content of 3.5 weight percent or greater 

 6xxx series alloys in the F temper 

 7xxx series alloys in the F, T5x, or T6x temper 

 2xx.x and 7xx.x series alloys 

 3xx.x series alloys that contain copper 

 5xx.x series alloys with a magnesium content of greater than 8 weight percent 
3.2-7 

The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

make the determination is technically substantiated. Tempers have been specifically developed 

to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 

combination which are not susceptible to SCC when used in piping, piping component, and tank 

applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. If it is determined that a 

material is not susceptible to SCC, the SLRA provides the components/locations where it is used, 

alloy composition, temper or condition, product form, and for tempers not addressed above, the 

basis used to determine the alloy is not susceptible and technical information substantiating 

the basis. 

Aggressive Environment: If the environment to which an aluminum alloy is exposed is not 

aggressive, such as dry gas or treated water, then cracking due to SCC will not occur and it is not 

an aging effect requiring management. Aggressive environments that are known to result in 

cracking due to SCC of susceptible aluminum alloys are aqueous solutions, air, condensation, 

and underground locations that contain halides (e.g., chloride). Halide concentrations should be 

considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated aqueous 

solutions and air, such as raw water, waste water, condensation, underground locations, and 

outdoor air, unless demonstrated otherwise. 

Halides could be present on the surface of the aluminum material if the component is 

encapsulated in a material such as insulation or concrete. In a controlled or uncontrolled indoor 

air, condensation, or underground environment, sufficient halide concentrations to cause 

SCC could be present due to secondary sources such as leakage from nearby components 

(e.g., leakage from insulated flanged connections or valve packing). If an aluminum component is 

exposed to a halide-free indoor air environment, not encapsulated in materials containing halides, 

and the exposure to secondary sources of moisture or halides is precluded, cracking due to SCC 

is not expected to occur. The plant-specific configuration can be used to demonstrate that 

exposure to halides will not occur. If it is determined that SCC will not occur because the 

environment is not aggressive, the SLRA provides the components and locations exposed to the 

environment, a description of the environment, basis used to determine the environment is not 

aggressive, and technical information substantiating the basis. The GALL-SLR Report 

AMP XI.M32, “One-Time Inspection,” and a review of plant-specific OE describe an acceptable 

means to confirm the absence of moisture or halides within the proximity of the aluminum 

component. 

If the environment potentially contains halides, the GALL-SLR Report AMP XI.M29, “Outdoor and 

Large Atmospheric Metallic Storage Tanks,” describes an acceptable program to manage 

cracking due to SCC of aluminum tanks. The GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” describes an acceptable program to manage cracking 

due to SCC of aluminum piping and piping components. The GALL-SLR Report AMP XI.M41, 

“Buried and Underground Piping and Tanks,” describes an acceptable program to manage 

cracking due to SCC of aluminum piping and tanks, which are buried or underground. The 

GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components” describes an acceptable program to manage cracking due to SCC of 

aluminum components that are not included in other AMPs. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

barriers include tightly-adhering coatings that have been demonstrated to be impermeable to 

aqueous solutions and air that contain halides. The GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” 
3.2-8 

describes an acceptable program to manage the integrity of a barrier coating for internal or 

external coatings. 

3.2.2.2.9 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

Loss of material due to general (steel only), crevice, or pitting corrosion and cracking due to SCC 

(SS only) can occur in steel and SS piping and piping components exposed to concrete. 

Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for 

steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through 

the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, 

which can penetrate the protective oxide layer created in the high alkalinity environment, can 

reach the surface of the metal. Carbonation can reduce the pH within concrete. The rate of 

carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability. 

Concrete with low permeability also reduces the potential for the penetration of water. Adequate 

air entrainment improves the ability of the concrete to resist freezing and thawing cycles and 

therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well 

as pitting and crevice corrosion can occur due to halides present in the water that penetrates to 

the surface of the metal. 

If the following conditions are met, loss of material is not considered to be an applicable aging 

effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

(ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) 

as cited in NUREG–1557; (b) plant-specific OE indicates no degradation of the concrete that 

could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

exposed to groundwater. For SS components loss of material and cracking due to SCC are not 

considered to be applicable aging effects as long as the piping is not potentially exposed to 

groundwater. Where these conditions are not met, loss of material due to general (steel only), 

crevice or pitting corrosion and cracking due to SCC (SS only) are identified as applicable aging 

effects. The GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” 

describes an acceptable program to manage these aging effects. 

3.2.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 

environment for a sufficient duration of time. Environments that can result in pitting and/or crevice 

corrosion of aluminum alloys are those that contain halides (e.g., chloride) in the presence of 

moisture. The moisture level and halide concentration in atmospheric and uncontrolled air are 

greatly dependent on geographical location and site-specific conditions. Moisture level and halide 

concentration should be considered high enough to facilitate pitting and/or crevice corrosion of 

aluminum alloys in atmospheric and uncontrolled air, unless demonstrated otherwise. The 

periodic introduction of moisture or halides into an environment from secondary sources should 

also be considered. Leakage of fluids from mechanical connections (e.g., insulated bolted flanges 

and valve packing); onto a component in indoor controlled air is an example of a secondary 

source that should be considered. Halide concentrations should be considered high enough to 

facilitate loss of material of aluminum alloys in untreated aqueous solutions, unless demonstrated 

otherwise. Plant-specific OE and the condition of aluminum alloy components are evaluated to 

determine if prolonged exposure to the plant-specific air, condensation, underground, or water 

environments has resulted in pitting or crevice corrosion. Loss of material due to pitting and 

crevice corrosion is not an aging effect requiring management for aluminum alloys if (a) 
3.2-9 

plant-specific OE does not reveal a history of loss of material due to pitting or crevice corrosion 

and (b) a one-time inspection demonstrates that the aging effect is not occurring or is occurring so 

slowly that it will not affect the intended function of the components. The applicant documents the 

results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to occur 

as the result of a source of moisture and halides. Alloy susceptibility may be considered when 

reviewing OE and interpreting inspection results. Inspections focus on the most susceptible alloys 

and locations. 

The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that the aging effect of loss of material due to pitting and 

crevice corrosion is not occurring at a rate that will affect the intended function of the components. 

If loss of material due to pitting or crevice corrosion has occurred and is sufficient to potentially 

affect the intended function of an SSC, the following AMPs describe acceptable programs to 

manage loss of material due to pitting and crevice corrosion: (i) the GALL-SLR Report 

AMP XI.M29, “Outdoor and Large Atmospheric Metallic Storage Tanks,” for tanks; (ii) the 

GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” for 

external surfaces of piping and piping components; (iii) the GALL-SLR Report AMP XI.M41, 

“Buried and Underground Piping and Tanks,” for underground piping, piping components and 

tanks; and (iv) the GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components” for internal surfaces of components that are not 

included in other AMPs. The timing of the one-time or periodic inspections is consistent with that 

recommended in the AMP selected by the applicant during the development of the SLRA. For 

example, one-time inspections would be conducted between the 50th and 60th year of operation, 

as recommended by the “detection of aging effects” program element in AMP XI.M32. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent loss of material due to 

pitting and crevice corrosion. Acceptable barriers include tightly-adhering coatings that have been 

demonstrated to be impermeable to aqueous solutions and air that contain halides. The GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” or equivalent program, describes an acceptable program to 

manage the integrity of a barrier coating. 

3.2.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.2.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and are based on the program elements 

of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs credited in the 

SLRA to confirm consistency with the GALL-SLR Report AMPs identified in Chapters X and XI. 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 
3.2-10 

10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, the 

difference should be reviewed and properly dispositioned. The reviewer should document the 

disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing AMP to be 

declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. The 

reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

plant AMP to be consistent with the GALL-SLR Report AMP and also that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the subsequent 

period of extended operation. The reviewer should review and document the disposition of 

all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.2.2.5 Final Safety Analysis Report Supplement 

The summary description of the programs and activities for managing the effects of aging for the 

subsequent period of extended operation in the FSAR Supplement should be sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

should contain information associated with the bases for determining that aging effects will be 

managed during the subsequent period of extended operation. The description should also 

contain any future aging management activities, including enhancements and commitments, to be 

completed before the subsequent period of extended operation. Table X-01 and Table XI-01 of 

the GALL-SLR Report provide examples of the type of information to be included in the FSAR 

Supplement. Table 3.2-2 lists the programs that are applicable for this SRP-SLR subsection.

3.2.3 Review Procedures 

For each area of review, the following review procedures are to be followed: 

3.2.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a re-review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to the GALL-SLR Report in its 

SLRA. In making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects have been addressed based on the NRC staff’s review of industry 

and plant-specific OE. 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review requires the reviewer to confirm 
3.2-11 

that the applicant has identified those aging effects for the engineered safety features system 

components that are contained in the GALL-SLR Report as applicable to its plant.

3.2.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Subsection 3.2.3.1 need to be applied first to all of the 

AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to which 

the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. 

3.2.3.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be TLAAs, 

as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Section 4.3 or 4.7 (as applicable) to determine whether the applicant has provided a 

sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria in 

10 CFR 54.21(c)(1)(i), (ii), or (iii). This includes staff’s review of those cumulative usage 

factor analyses that qualify as TLAAs and are based on plant-specific, stress-based 

calculation methods. 

3.2.3.2.2 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

and crevice corrosion of SS and nickel alloy piping and piping components exposed to any air, 

condensation, or underground environment, when the component is: (a) uninsulated; 

(b) insulated; (c) in the vicinity of insulated components where the presence of sufficient halides 

(e.g., chlorides) and moisture is possible; or (d) in the vicinity of potentially transportable halogens. 

The possibility of pitting and crevice corrosion also extends to indoor components located in close 

proximity to sources of outdoor air (e.g., components near intake vents). 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals loss of material due to pitting or crevice corrosion in 

SS and nickel alloys, the reviewer determines whether an adequate program is credited to 

manage the aging effect. If the review of plant-specific OE reveals that loss of material due to 

pitting and crevice corrosion is not applicable, the reviewer verifies that GALL-SLR Report 

AMP XI.M32, “One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that loss of material 

due to pitting and crevice corrosion has occurred in the outdoor air environment but not the indoor 

air environment. The applicant could further categorize the indoor air locations as those where 

leakage could impinge on the SS or nickel alloy component’s surface (e.g., leakage from 

mechanical connections) and those where there is not a potential for leakage. When the applicant 

chooses to conduct its OE search in this manner, the reviewer is to also confirm that the applicant 
3.2-12 

has adequately addressed the potential for the periodic introduction of either moisture or halides 

from secondary sources. Secondary sources of moisture or halides should be considered for all 

environments including indoor conditioned air. Typical secondary sources of moisture or halides 

include: leakage from mechanical connections; leakage into vaults; insulation containing halides; 

and outdoor air intrusion. Grouping of environments consistent with that described in the 

detection of aging effects program element of GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.2.3.2.3 Loss of Material Due to General Corrosion and Flow Blockage Due to Fouling 

The GALL-SLR Report recommends further evaluation of programs to manage loss of material 

due to general corrosion and flow blockage due to fouling in the spray nozzles and flow orifices of 

the drywell and suppression chamber spray system spray exposed to air—indoor uncontrolled. 

This is necessary to prevent the plugging of spray nozzles and flow orifices of the BWR drywell 

and suppression chamber spray system. The wetting and drying of these components can 

accelerate corrosion in the system and lead to flow blockage from an accumulation of corrosion 

products. The reviewer reviews the applicant’s proposed program on a case-by-case basis to 

ensure that an adequate program will be in place for the management of loss of material due to 

general corrosion and flow blockage due to fouling of these components. If the applicant has 

cited GALL-SLR Report AMP XI.M32, “One-Time Inspection,” to manage the aging effects, the 

reviewer determines if: (a) plant-specific procedures exist to drain the normally dry portions that 

have been wetted during normal plant operation or inadvertently; (b) the applicant has 

documented that the plant-specific configuration of the drains and piping allow sufficient draining 

to empty the normally dry pipe; and (c) based on a review of a sample of plant-specific OE, loss of 

material or flow blockage due to fouling has not occurred.

3.2.3.2.4 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

The GALL-SLR Report recommends further evaluation to manage cracking due to SCC of SS 

piping, piping components, and tanks exposed to air and underground environments containing 

sufficient halides (e.g., chlorides) and in which condensation is possible. The possibility of 

cracking also extends to components exposed to air which has recently been introduced into 

buildings (i.e., components near intake vents) or where the component is in the vicinity of 

insulated components. 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals SCC in SS alloys, the reviewer determines whether 

an adequate program is credited to manage the aging effect. If the review of plant-specific OE 

reveals that SCC is not applicable, the reviewer verifies that the GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that SCC has 
3.2-13 

occurred in the outdoor air environment but not the indoor air environment. The applicant could 

further categorize the indoor air locations as those where leakage could impinge on the SS 

component’s surface (e.g., leakage from mechanical connections) and those where there is not a 

potential for leakage. When the applicant chooses to conduct its OE search in this manner, the 

reviewer also is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include: leakage from mechanical connections; 

leakage into vaults; insulation containing halides; and outdoor air intrusion. Grouping of 

environments consistent with that described in the detection of aging effects program element of 

GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

3.2.3.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMPs for SLR should contain the elements of corrective actions, the confirmation 

process, and administrative controls. Safety-related components are covered by 10 CFR Part 50, 

Appendix B, which is adequate to address these program elements. However, Appendix B does 

not apply to nonsafety-related components that are subject to an AMR for SLR. Nevertheless, the 

applicant has the option to expand the scope of its 10 CFR Part 50, Appendix B program to 

include these components and address the associated program elements. If the applicant 

chooses this option, the reviewer verifies that the applicant has documented such a commitment 

in the FSAR Supplement. If the applicant chooses alternative means, the branch responsible for 

quality assurance should be requested to review the applicant’s proposal on a case-by-case 

basis. 

3.2.3.2.6 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to 

ensure that the AMPs are effective to manage the aging effects for which they are created. The 

AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined 

through the evaluation of OE that the effects of aging may not be adequately managed. 

Additional information is in Appendix A.4, “Operating Experience for Aging Management 

Programs.” 

3.2.3.2.7 Loss of Material Due to Recurring Internal Corrosion 

The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

aging effects. The reviewer conducts an independent review of plant-specific OE to determine 

whether the plant is currently experiencing recurring internal corrosion. This further evaluation 

item is applicable if the search of plant-specific OE reveals repetitive occurrences. The criteria for 

recurrence is (a) a 10-year search of plant specific OE reveals the aging effect has occurred in 
3.2-14 

three or more refueling outage cycles; or (b) a 5-year search of plant specific OE reveals the 

aging effect has occurred in two or more refueling outage cycles as a result of which the 

component either did not meet plant-specific acceptance criteria or experienced a reduction in 

wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The reviewer should evaluate plant-specific OE examples to determine if the chosen AMP should 

be augmented. For example, during a 10-year search of plant-specific OE, two instances of a 

360 degree 30 percent wall loss occurred at copper alloy to steel joints. Neither the significance 

of the aging effect nor the frequency of occurrence of aging effect threshold has been exceeded. 

Nevertheless, the OE should be evaluated to determine if the AMP that is proposed to manage 

the aging effect is sufficient (e.g., method of inspection, frequency of inspection, number of 

inspections) to provide reasonable assurance that the CLB intended functions of the component 

will be met throughout the subsequent period of extended operation. 

The reviewer determines whether a proposed program is adequate to manage recurring internal 

corrosion by evaluating the proposed AMP against the criteria in SRP-SLR Section 3.2.2.2.7. 

3.2.3.2.8 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

The GALL-SLR Report recommends the further evaluation of aluminum components (i.e., piping, 

piping components, and tanks) exposed to air, condensation, underground, or aqueous solutions 

that contain halides to manage cracking due to SCC. The reviewer must first determine if 

cracking due to SCC is applicable and requires aging management. Cracking is to be considered 

applicable unless it is demonstrated that one of the two acceptance criteria are met by 

demonstrating that an aggressive environment is not present or the specific material is not 

susceptible, as discussed in Section 3.2.2.2.8. Additionally, guidance is also provided on the 

review of the third condition necessary for SCC to occur, a sustained tensile stress. Each of three 

conditions is evaluated based on the review procedures below. 

If the material used to fabricate the component being evaluated is not susceptible to SCC then 

cracking due to SCC is not an aging effect requiring management. When determining if an 

aluminum alloy is susceptible to SCC the reviewer is to verify the material’s (a) alloy composition, 

(b) condition or temper, and (c) product form. Additionally, if the material was produced using a 

process specifically developed to provide a SCC resistant microstructure then the reviewer will 

consider the effects of this processing in the review. Once the material information has been 

established the reviewer is to evaluate the technical justification used to substantiate that the 

material is not susceptible to SCC when exposed to an aggressive environment and sustained 

tensile stress. The reviewer will evaluate all documentation and references used by the applicant 

as part of a technical justification. 

If the environment to which an aluminum alloy is exposed is not aggressive, such as dry gas, or 

treated water, then cracking due to SCC is not an aging effect requiring management. The 

environments cited in the AMR line items in the GALL-SLR Report that reference this further 

evaluation are considered to be aggressive and potentially containing halide concentrations that 

facilitate SCC of aluminum alloys. The reviewer is to verify that components are not also 

periodically exposed to nontypical environments that would be categorized as aggressive, such as 

secondary sources of moisture or halides, including outdoor air which has recently been 

introduced into a building and the leakage/seepage of untreated aqueous solutions into a building 

or underground vault. Controlled indoor air is not considered aggressive unless secondary 

sources of moisture or halides are present. When applicable, the staff reviews the basis for the 

applicant’s claim that the plant configuration precludes the potential presence of secondary 
3.2-15 

sources of moisture or halides. Using information provided by the applicant, the reviewer will also 

evaluate the chemical composition of applicable encapsulating materials (e.g., concrete, 

insulation) for halides. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

If the sustained tensile stress being experienced by a component is below the SCC threshold 

value, then cracking is not an aging effect requiring management. Many aluminum alloys do not 

have a true SCC threshold stress, although a practical SCC threshold value can be determined 

based on the material, service environment, and duration of intended function. The basis for the 

SCC threshold value is to be evaluated to determine its applicability. The magnitude of the 

maximum tensile service stress (applied and residual) experienced by the component is to be 

evaluated to verify that the stress levels are bounded by the SCC threshold value. 

The information necessary to determine if SCC is applicable based on the sustained service 

stress is often not readily available. The SCC threshold stress level is dependent on both the 

alloy (e.g., chemical composition, processing history, and microstructure) and service 

environment. Furthermore, the magnitude and state of the residual stress sustained by a 

component is typically not fully characterized. The reviewer must determine the adequacy of both 

the SCC threshold value being used by the applicant and the magnitude of the tensile stress 

being experienced by the component. The evaluation of the SCC threshold value includes the 

verification that the: (a) test method used to establish the threshold value is standardized and 

recognized by the industry, (b) data are statistically significant or conservative, and (c) data are for 

a relevant alloy, temper, product form, and environment. The evaluation of the tensile stress 

being experienced by the component includes the verification that the stress analysis accounts for 

(a) all applied and residual stresses and (b) stress riser that can initiate SCC cracks, such as 

corrosion pits and fabrication defects. 

Documentation that may assist the reviewer in determining if cracking due to SCC is applicable 

and requires aging management include: (a) component drawings, (b) applicable codes 

or specifications used in the design, fabrication, and installation of the component, 

(c) material-specific material certification data and lot release data, (d) maintenance records, 

and (e) plant-specific OE. 

If it is determined that cracking due to SCC is applicable, the reviewer is to evaluate the applicants 

proposed AMP to ensure that cracking is adequately managed so that the component’s intended 

functions will be maintained consistent with the CLB for the subsequent period of extended 

operation. The GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric Metallic 

Storage Tanks,” describes an acceptable program to manage cracking due to SCC of aluminum 

tanks. The GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” describes an acceptable program to manage cracking due to SCC of aluminum 

piping and piping components. The GALL-SLR Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” describes an acceptable program to manage cracking due to SCC of 

aluminum piping and tanks which are buried or underground. The GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components” 
3.2-16 

describes an acceptable program to manage cracking due to SCC of aluminum components that 

are not included in other AMPs. 

3.2.3.2.9 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

The GALL-SLR Report recommends that for steel piping and piping components exposed to 

concrete, if the following conditions are met, loss of material is not considered to be an applicable 

aging effect for steel: (a) 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; 

(b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of 

water to the metal surface; and (c) the piping is not potentially exposed to groundwater. For SS 

piping and piping components, loss of material and cracking due to SCC are not considered to be 

applicable aging effects as long as the piping is not potentially exposed to groundwater. Where 

these conditions are not met, loss of material due to general (steel only), crevice or pitting 

corrosion and cracking due to SCC (SS only) are identified as applicable aging effects. The 

GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes an 

acceptable program to manage these aging effects. 

The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-tocement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

reviewer should evaluate plant-specific OE to determine whether concrete degradation sufficient 

to allow water intrusion has occurred. 

3.2.3.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

The GALL-SLR Report recommends a further evaluation to determine whether an AMP is needed 

to manage loss of material due to pitting and crevice corrosion of aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 

environment. The reviewer is to conduct an independent assessment of plant-specific OE during 

the AMP audit to confirm that the applicant’s evaluation of its OE is adequate. 

The reviewer is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include leakage from mechanical connections, 

leakage into vaults, insulation containing halides, and outdoor air intrusion. Grouping of 

environments consistent with that found in the GALL-SLR Report Section IX.D is appropriate. 

The grouping of OE search results based on environmental factors or plant configuration may be 

appropriate. The reviewer is to verify that the considerations given to groupings based on 

environmental factors and/or plant configuration have a substantiated technical basis. 

Components in the vicinity of secondary sources of moisture or halides may be treated as a 

separate population when performing inspections and interpreting results due to plant-specific 

configurations. 

The grouping of alloys based on relative susceptibility to loss of material may also be appropriate. 

The reviewer is to verify that the considerations given to alloy susceptibility and/or grouping have 

a substantiated technical basis. The high strength heat treatable aluminum alloys (2xxx and 7xxx 

series) may be treated as a separate population when performing inspections and interpreting 

results due to their relatively lower corrosion resistance. The relative susceptibility of moderate 
3.2-17 

and lower strength alloys varies based on composition (primarily weight percent Cu, Mg, and Fe) 

and temper designation. 

The reviewer is to determine whether an adequate program is credited to manage the aging effect 

if the OE reveals that loss of material is applicable or the applicant elects to manage loss of 

material due to pitting or crevice corrosion. The reviewer is to verify that the SLRA cites the use of 

the GALL-SLR Report AMP XI.M32, “One-Time Inspection,” for all aluminum piping, piping 

components, and tanks exposed to air, condensation, or underground environments when 

confirming that the aging effect is not applicable based on the OE evaluation. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.2.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging effects, 

listed the appropriate combination of materials and environments, and AMPs that will adequately 

manage the aging effects. The AMP credited by the applicant could be an AMP that is described 

and evaluated in the GALL-SLR Report or a plant-specific program. Review procedures are 

described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.2.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA between the SLRA AMP and the GALL-SLR Report AMP with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the engineered safety features components are summarized in Table 3.2-1 of this 

SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR 

Report, Chapter V, presenting detailed information summarized by this row. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.2.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in its FSAR Supplement information for 

aging management of the engineered safety features. Table 3.2-2 lists the AMPs that are 
3.2-18 

applicable for this SRP-SLR subsection. The reviewer also confirms that the applicant has 

provided information for Subsection 3.2.3.3, “Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons Learned for Subsequent License 

Renewal Report.” 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

3.2.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 

On the basis of its review, as discussed above, the staff concludes that the 

applicant has demonstrated that the aging effects associated with the engineered 

safety features systems components will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the subsequent 

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 they adequately describe the AMPs credited for managing 

aging of the engineered safety features systems, as required by 

10 CFR 54.21(d). 

3.2.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.2.6 References 

1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants, LWR Edition.” Agencywide Documents Access and 

Management System (ADAMS) Accession No. ML070630046. Washington, DC: 

U.S. Nuclear Regulatory Commission. March 2007. 
3.2-19 

2. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License Renewal.” 

Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 

3. ACI. ACI Standard 318-95, “Building Code Requirements for Reinforced Concrete and 

Commentary.” Farmington Hills, Michigan: American Concrete Institute. 1995. 

4. ACI. ACI Standard 349-85, “Code Requirements for Nuclear Safety-Related Concrete 

Structures.” Farmington Hills, Michigan: American Concrete Institute. 1985. 

5. ANSI. ANSI Standard H35.1/H35.1M, “Alloy and Temper Designation Systems for 

Aluminum.” New York, New York: American National Standards Institute, Inc. 2013. 

6. ASM. Corrosion of Aluminum and Aluminum Alloys. J. R. Davis, ed. Materials Park, 

Ohio: ASM International. 1999. 

7. NRL. Stress-Corrosion Cracking in High Strength Steels and in Titanium and Aluminum 

Alloys. B. F. Brown, ed. Washington, DC: Naval Research Laboratory. 1972. 
3.2-20 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 001 BWR/PWR Stainless steel, steel 

piping, piping components exposed to any environment 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.2.2.2.1) 

V.D1.E-13 V.D2.E-10 

D 002 D 003 M 004 BWR/PWR Stainless steel, 

nickel alloy piping, piping components exposed to air, condensation (external) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.B.EP-107a V.B.EP-107b V.B.EP-107d V.C.EP-107a V.C.EP-107b V.C.EP-107d V.D1.EP-107aV.D1.EP-107bV.D1.EP-107dV.D2.EP-107aV.D2.EP-107bV.D2.EP-107d 

M 005 PWR Stainless steel 

orifice (miniflow recirculation when centrifugal HPSI pumps are used for normal charging) exposed to treated borated water 

Loss of material due to erosion 

AMP XI.M32, "One-Time Inspection" 

No V.D1.E-24 
3.2-21 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 006 BWR Metallic drywell and 

suppression chamber spray system (internal surfaces): flow orifice; spray nozzles exposed to air – indoor uncontrolled, condensation 

Loss of material due to general, pitting, crevice corrosion; flow blockage due to fouling 

AMP XI.M32, "One-Time Inspection," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.2.2.2.3) 

V.D2.EP-113aV.D2.EP-113b 

M 007 BWR/PWR Stainless steel 

piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M32, 

"One Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.4) 

V.A.EP-103b V.A.EP-103c V.A.EP-103d V.A.EP-103e V.B.EP-103b V.B.EP-103c V.B.EP-103d V.B.EP-103e V.C.EP-103b V.C.EP-103c V.C.EP-103d V.C.EP-103e V.D1.EP-103bV.D1.EP-103cV.D1.EP-103dV.D1.EP-103eV.D2.EP-103bV.D2.EP-103cV.D2.EP-103dV.D2.EP-103e 

M 008 PWR Copper alloy (>15% 

Zn) piping, piping components exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No V.E.EP-38 
3.2-22 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 009 PWR Steel external 

surfaces exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No V.E.E-28 

M 010 BWR/PWR Cast austenitic 

stainless steel piping, piping components exposed to treated borated water >250°C (>482°F), treated water >250°C (>482°F) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)" 

No V.D1.E-47 

V.D2.E-11 

M 011 BWR/PWR Steel piping, piping 

components exposed to steam, treated water 

Wall thinning due to flowaccelerated corrosion AMP XI.M17, "Flow-Accelerated 

Corrosion" 

No V.C.E-09 

V.D1.E-09 V.D2.E-07 V.D2.E-09 

M 012 BWR/PWR High-strength steel 

closure bolting exposed to air, soil, underground 

Cracking due to SCC; cyclic loading 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-03 

D 013 M 014 BWR/PWR Stainless steel, 

steel, nickel alloy closure bolting exposed to airindoor uncontrolled, air-outdoor, condensation 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-02 

M 015 BWR/PWR Metallic closure 

bolting exposed to any environment, soil underground 

Loss of preload due to thermal effects, gasket creep, self-loosening 

AMP XI.M18, "Bolting Integrity" 

No V.E.EP-116 

M 016 BWR/PWR Steel piping, piping 

components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.C.EP-62 

V.D2.EP-60 
3.2-23 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 017 BWR/PWR Aluminum piping, 

piping components exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.D1.EP-71 

V.D2.EP-71 

D 018  019 BWR/PWR Stainless steel heat 

exchanger tubes exposed to treated water, treated borated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-20 

V.D2.EP-74 V.D1.E-20 

M 020 PWR Stainless steel, steel 

(with stainless steel or nickel alloy cladding) piping, piping components, tanks exposed to treated borated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-12 

V.D1.E-12 

D 021 M 022 BWR/PWR Nickel alloy, 

stainless steel heat exchanger components, piping, piping components, tanks exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-428 

V.A.EP-41 V.C.EP-63 V.D1.E-428 V.D2.E-428 V.D1.EP-41 V.D2.EP-73 

M 023 BWR/PWR Steel heat 

exchanger components, piping, piping components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No V.A.EP-90 

V.C.E-22 V.D1.EP-90 V.D2.EP-90 
3.2-24 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 024 PWR Stainless steel 

piping, piping components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No V.C.E-34 

V.D1.EP-55 

M 025 BWR/PWR Stainless steel heat 

exchanger components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No V.A.EP-91 

V.D1.EP-91 V.D2.EP-91 

D 026 E 027 BWR/PWR Stainless steel, steel 

heat exchanger tubes exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No V.A.E-21 

V.D1.E-21 V.D2.E-21 V.D2.E-23 

M 028 BWR/PWR Stainless steel 

piping, piping components exposed to closedcycle cooling water >60°C (>140°F) 

Cracking due to SCC AMP XI.M21A, 

"Closed Treated Water Systems" 

No V.A.EP-98 

V.C.EP-98 V.D1.EP-98 V.D2.EP-98 

M 029 BWR/PWR Steel piping, piping 

components exposed to closedcycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.C.EP-99 

M 030 BWR/PWR Steel heat 

exchanger components exposed to closedcycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-92 

V.D1.EP-92 V.D2.EP-92 

M 031 BWR/PWR Stainless steel heat 

exchanger components, piping, piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-93 

V.A.EP-95 V.C.EP-95 V.D1.EP-93 V.D1.EP-95 V.D2.EP-93 V.D2.EP-95 
3.2-25 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 032 BWR/PWR Copper alloy heat 

exchanger components, piping, piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-94 

V.A.EP-97 V.B.EP-97 V.D1.EP-94 V.D1.EP-97 V.D2.EP-94 V.D2.EP-97 

 033 BWR/PWR Copper alloy, 

stainless steel heat exchanger tubes exposed to closedcycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-100 

V.A.EP-96 V.D1.EP-96 V.D2.EP-96 

M 034 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components, heat exchanger components exposed to closedcycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.A.EP-27 

V.A.EP-37 V.B.EP-27 V.B.EP-37 V.D1.EP-27 V.D1.EP-37 V.D2.EP-27 V.D2.EP-37 

M 035 PWR Gray cast iron motor 

cooler exposed to closed-cycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.A.E-43 

V.D1.E-43 

M 036 PWR Gray cast iron, 

ductile iron piping, piping components exposed to closedcycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.D1.EP-52 

M 037 BWR/PWR Gray cast iron, 

ductile iron piping, piping components exposed to soil 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.B.EP-54 

V.D1.EP-54 V.D2.EP-54 
3.2-26 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 038 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, condensation 

Hardening or loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.EP-59 

D 039 M 040 BWR/PWR Steel external 

surfaces exposed to air – indoor uncontrolled, air – outdoor, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-44 

D 041 M 042 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation (external) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.EP-114b V.E.EP-114c V.E.EP-114d 

M 043 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, condensation 

Hardening or loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.B.EP-58 

V.A.E-427 V.B.E-427 V.D1.E-427 V.D2.E-427 
3.2-27 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 044 BWR/PWR Steel piping, piping 

components, ducting, ducting components exposed to air – indoor uncontrolled 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-29 

V.B.E-25 V.D2.E-29 

M 045 PWR Steel encapsulation 

components exposed to air – indoor uncontrolled 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.EP-42 

V.C.EP-42 V.D1.EP-42 

M 046 BWR/PWR Steel piping, piping 

components exposed to condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.B.E-27 

V.D1.E-27 V.D2.E-27 

M 047 PWR Steel encapsulation 

components exposed to air with borated water leakage 

Loss of material due to general, pitting, crevice, boric acid corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.EP-43 

V.C.EP-43 V.D1.EP-43 
3.2-28 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 048 BWR/PWR Stainless steel, 

nickel alloy piping, piping components, tanks exposed to air, condensation (internal) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.A.EP-81a V.A.EP-81b V.A.EP-81c V.A.EP-81d V.D1.EP-81a V.D1.EP-81b V.D1.EP-81c V.D1.EP-81d V.D2.EP-61a V.D2.EP-61b V.D2.EP-61c V.D2.EP-61d 

M 049 BWR/PWR Steel piping, piping 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-77 

V.D1.EP-77 V.D2.EP-77 

M 050 BWR/PWR Copper alloy, 

stainless steel piping, piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-76 

V.D1.EP-76 V.D1.EP-80 V.D2.EP-76 
3.2-29 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 051 BWR/PWR Steel, copper alloy, 

stainless steel heat exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-75 

V.A.EP-78 V.A.EP-79 V.D1.EP-75 V.D1.EP-78 V.D1.EP-79 V.D2.EP-75 V.D2.EP-78 V.D2.EP-79 

M 052 BWR/PWR Steel piping, piping 

components exposed to soil, concrete, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.EP-111 

V.E.EP-123 

M 053 BWR/PWR Stainless steel, 

nickel alloy piping, piping components, tanks, exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.EP-72 

D 053a M 054 BWR Stainless steel, 

nickel alloy piping, piping components greater than or equal to 4 NPS exposed to treated water >93°C (>200°F) 

Cracking due to SCC, IGSCC 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

No V.D2.E-37 

M 055 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.2.2.2.9) 

V.F.EP-112 
3.2-30 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 056 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation (internal) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP-XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.A.EP-3b V.A.EP-3c V.A.EP-3d V.D1.EP-3b V.D1.EP-3c V.D1.EP-3d V.D2.EP-3b V.D2.EP-3c V.D2.EP-3d 

M 057 BWR/PWR Copper alloy piping, 

piping components exposed to air, condensation, gas 

None None No V.F.EP-10 

M 058 PWR Copper alloy, copper 

alloy (>8% Al) piping, piping components exposed to air with borated water leakage 

None None No V.F.EP-12 

M 059 BWR/PWR Galvanized steel 

ducting, ducting components, piping, piping components exposed to air – indoor controlled 

None None No V.F.EP-14 
3.2-31 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 060 BWR/PWR Glass piping 

elements exposed to air, underground, lubricating oil, raw water, treated water, treated borated water, air with borated water leakage, condensation, gas, closed-cycle cooling water 

None None No V.F.EP-15 

V.F.EP-16 V.F.EP-28 V.F.EP-29 V.F.EP-30 V.F.EP-65 V.F.EP-66 V.F.EP-67 V.F.EP-68 

D 061 M 062 BWR/PWR Nickel alloy piping, 

piping components exposed to air with borated water leakage 

None None No V.F.EP-115 

M 063 BWR/PWR Stainless steel 

piping, piping components exposed to air with borated water leakage, gas 

None None No V.F.EP-19 

V.F.EP-22 

M 064 BWR/PWR Steel piping, piping 

components exposed to air – indoor controlled, gas 

None None No V.F.EP-4 

V.F.EP-7 

M 065 BWR/PWR Metallic piping, 

piping components exposed to treated water, treated borated water 

Wall thinning due to erosion AMP XI.M17, 

"Flow-Accelerated Corrosion" 

No V.D1.E-407 

V.D2.E-408 
3.2-32 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 066 BWR/PWR Metallic piping, 

piping components, tanks exposed to raw water, waste water 

Loss of material due to recurring internal corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.2.2.2.7) 

V.A.E-400 V.B.E-400 V.C.E-400 V.D1.E-400 V.D2.E-400 

M 067 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.D1.E-405 

V.D2.E-405 

M 068 BWR/PWR Steel tanks (within 

the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete, air, condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.D1.E-402 

V.D2.E-402 

M 069 BWR/PWR Insulated steel 

piping, piping components, tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" or AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.E.E-403a 

V.E.E-403b 
3.2-33 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 070 BWR/PWR Steel, stainless 

steel, aluminum tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to treated water, treated borated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC (steel, stainless steel only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.A.E-404 

V.D1.E-404 V.D2.E-404 

M 071 BWR/PWR Insulated copper 

alloy (>15% Zn or >8% Al) piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No V.E.E-406 

M 072 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, treated borated water 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage; loss of material or cracking for cementitious coatings/linings 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-401 

V.B.E-401 V.C.E-401 V.D1.E-401 V.D2.E-401 

M 073 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, treated borated water, lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-414 

V.B.E-414 V.C.E-414 V.D1.E-414 V.D2.E-414 
3.2-34 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 074 BWR/PWR Gray cast iron, 

ductile iron piping, piping components with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, treated borated water, waste water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-415 

V.B.E-415 V.C.E-415 V.D1.E-415 V.D2.E-415 

D 075 N 076 BWR/PWR Stainless steel, 

steel, nickel alloy, copper alloy closure bolting exposed to treated water, treated borated water, raw water, waste water, lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC (steel, copper alloy in raw water, waste water only) 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-418 

D 077 N 078 BWR/PWR Stainless steel, 

steel, aluminum piping, piping components, tanks exposed to soil, concrete 

Cracking due to SCC (steel in carbonate/bicarbonate environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-420 

N 079 BWR/PWR Stainless steel 

closure bolting exposed to air, soil, concrete, underground 

Cracking due to SCC AMP XI.M18, 

"Bolting Integrity" 

No V.E.E-421 
3.2-35 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 080 BWR/PWR Stainless steel 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.4) 

V.E.E-423a V.E.E-423b V.E.E-423c 

N 081 BWR/PWR Stainless steel, 

steel, aluminum, copper alloy, titanium heat exchanger tubes exposed to air, condensation 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-424 

D 083 D 084 D 085 D 086 N 087 BWR/PWR Non-metallic thermal 

insulation exposed to air, condensation 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-422 

D 089 N 090 BWR/PWR Steel components 

exposed to treated water, treated borated water, raw water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "One Time Inspection" 

No V.A.E-434 

V.B.E-434 V.C.E-434 V.D1.E-434 V.D2.E-434 

N 091 BWR/PWR Stainless steel 

piping, piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.2.2.2.9) 

V.F.EP-20 
3.2-36 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

D 092 D 095 N 096 BWR/PWR Steel, stainless steel 

piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.D1.E-439 

V.D2.E-440 

D 097 N 098 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components exposed to soil 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.D1.E-441 

V.D2.E-441 

N 099 BWR/PWR Stainless steel, 

nickel alloy tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-442a V.E.E-442b V.E.E-442c V.E.E-442d 
3.2-37 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 100 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation (internal), raw water, waste water 

Cracking due to SCC AMP XI.M32, 

"One Time Inspection," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.8) 

V.A.E-443b V.A.E-443c V.A.E-443d V.B.E-443b V.B.E-443c V.B.E-443d V.D1.E-443b V.D1.E-443c V.D1.E-443d V.D2.E-443b V.D2.E-443c V.D2.E-443d 

N 101 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation (external) 

Cracking due to SCC AMP XI.M32, 

"One Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.8) 

V.E.E-444b V.E.E-444c V.E.E-444d 
3.2-38 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 102 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation, soil, concrete, raw water, waste water 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "OneTime Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.8) 

V.D1.E-445a V.D1.E-445b V.D1.E-445c V.D2.E-445a V.D2.E-445b V.D2.E-445c 

N 103 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.4) 

V.D1.E-446a V.D1.E-446b V.D1.E-446c V.D2.E-446a V.D2.E-446b V.D2.E-446c 

N 104 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.D1.E-447 

V.D2.E-447 
3.2-39 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 105 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.D1.E-448a V.D1.E-448b V.D1.E-448c V.D2.E-448a V.D2.E-448b V.D2.E-448c 

N 106 BWR/PWR Stainless steel, 

nickel alloy tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.D1.E-449a V.D1.E-449b V.D1.E-449c V.D2.E-449a V.D2.E-449b V.D2.E-449c 
3.2-40 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 107 BWR/PWR Insulated stainless 

steel, nickel alloy piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-450a V.E.E-450b V.E.E-450c V.E.E-450d 

N 108 BWR/PWR Insulated stainless 

steel piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.4) 

V.E.E-451a V.E.E-451b V.E.E-451c V.E.E-451d 
3.2-41 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 109 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.8) 

V.E.E-452a V.E.E-452b V.E.E-452c V.E.E-452d 

N 110 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.8) 

V.E.E-453a V.E.E-453b V.E.E-453c 
3.2-42 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 111 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.E-454a V.E.E-454b V.E.E-454c 

N 112 BWR/PWR Stainless steel, 

nickel alloy underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-455a V.E.E-455b V.E.E-455c 

D 113 N 114 BWR/PWR Stainless steel, 

nickel alloy piping, piping components exposed to treated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.B.E-457 

V.C.E-457 V.D2.E-457 

N 115 BWR/PWR Titanium heat 

exchanger tubes exposed to treated water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-458 

V.D1.E-458 V.D2.E-458 
3.2-43 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 116 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to treated water 

None None No V.F.E-459 

N 117 BWR/PWR Titanium heat 

exchanger tubes exposed to closedcycle cooling water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.E-460 

V.D1.E-460 V.D2.E-460 

N 118 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to closedcycle cooling water 

None None No V.F.E-461 
3.2-44 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 119 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "OneTime Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.E-462a V.E.E-462b V.E.E-462c V.E.E-462d 

N 120 BWR/PWR Aluminum piping, 

piping components, tanks exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-463 
3.2-45 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 121 BWR/PWR Aluminum piping, 

piping components, tanks exposed to raw water, waste water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "OneTime Inspection," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.E-464a V.E.E-464b V.E.E-464c V.E.E-464d 

N 122 BWR/PWR Elastomer piping, 

piping components, seals exposed to air 

Loss of material due to wear AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No V.E.E-465 

N 123 BWR/PWR Elastomer piping, 

piping components, seals exposed to air 

Loss of material due to wear AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-466 

V.B.E-466 V.C.E-466 V.D1.E-466 V.D2.E-466 

N 124 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air with borated water leakage 

None None No V.F.E-467 

N 125 BWR/PWR Steel closure bolting 

exposed to soil, concrete, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-468 
3.2-46 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 126 BWR/PWR Titanium, super 

austenitic piping, piping components, tanks, closure bolting exposed to soil, concrete, underground 

Loss of material due to pitting, crevice corrosion, MIC (except for titanium; soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-469 

N 127 BWR/PWR Copper alloy piping, 

piping components exposed to concrete 

None None No V.F.E-470 

N 128 BWR/PWR Copper alloy piping, 

piping components exposed to soil, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-471 

N 129 BWR/PWR Stainless steel tanks 

exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No V.D1.E-472 

V.D2.E-472 

N 130 BWR/PWR Steel heat 

exchanger components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-473 

V.D1.E-473 V.D2.E-473 

N 131 BWR/PWR Aluminum piping, 

piping components exposed to raw water 

Flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-474 

V.B.E-474 V.D1.E-474 V.D2.E-474 

N 132 BWR/PWR Titanium (ASTM 

Grades 3, 4, or 5) heat exchanger tubes exposed to raw water 

Cracking due to SCC AMP XI.M20, 

"Open-Cycle Cooling Water System" 

No V.A.E-475 

V.D1.E-475 V.D2.E-475 
3.2-47 

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of 

the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 133 BWR/PWR Titanium piping, 

piping components, heat exchanger components exposed to raw water 

Cracking due to SCC, flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No V.B.E-476 

V.C.E-476 V.D2.E-476 

N 134 BWR/PWR Polymeric piping, 

piping components, ducting, ducting components, seals exposed to air, condensation, raw water, raw water (potable), treated water, waste water, underground, concrete, soil 

Hardening or loss of strength due to polymeric degradation; loss of material due to peeling, delamination, wear; cracking or blistering due to exposure to ultraviolet light, ozone, radiation, or chemical attack; flow blockage due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-477b 

V.B.E-477b V.D1.E-477b V.D2.E-477b V.E.E-477a 
3.2-48 

Table 3.2-2 AMPs and Additional Guidance Appendices Recommended for Aging 

Management of Engineered Safety Features 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP XI.M2 Water Chemistry 

AMP XI.M7 BWR Stress Corrosion Cracking 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless 

Steel (CASS) 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M29 Outdoor and Large Atmospheric Metallic Storage Tanks 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 
3.3-1 

3.3 Aging Management of Auxiliary Systems 

Review Responsibilities 

Primary— The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.3.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management program (AMP) of the auxiliary systems for subsequent license renewal (SLR). For 

a recent vintage plant, the information related to the auxiliary systems contained in Chapter 9, 

“Auxiliary Systems,” of the plant’s Final Safety Analysis Report (FSAR) consistent with the 

“Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants” 

(NUREG–0800). The auxiliary systems contained in this review plan section are generally 

consistent with those contained in NUREG–0800 except for refueling water, chilled water, heat 

removal, condenser circulating water, and condensate storage system. For older plants, the 

location of applicable information is plant-specific because an older plant’s FSAR may have 

predated NUREG–0800. 

Typical auxiliary systems that are subject to an AMR for SLR are new fuel storage, spent fuel 

storage, spent fuel pool cooling and cleanup [boiling water reactor/pressurized water reactor 

(BWR/PWR)], suppression pool cleanup (BWR), overhead heavy load and light load (related to 

refueling) handling, open-cycle cooling water, closed-cycle cooling water, ultimate heat sink, 

compressed air, chemical and volume control (PWR), standby liquid control (BWR), reactor water 

cleanup (BWR), shutdown cooling (older BWR), control room area ventilation, auxiliary and 

radwaste area ventilation, primary containment heating and ventilation, diesel generator building 

ventilation, fire protection, diesel fuel oil, and emergency diesel generator. This review plan 

section also includes structures and components in nonsafety-related systems that are not 

connected to safety-related systems, structures, and components (SSCs) but have a spatial 

relationship such that their failure could adversely impact the performance of a safety-related 

SSC intended function. Examples of such nonsafety-related systems may be plant drains, liquid 

waste processing, potable/sanitary water, water treatment, process sampling, and cooling 

water systems. 

Aging management is reviewed, following the guidance in this Standard Review Plan for Review 

of Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) Section 3.1, 

for portions of the chemical and volume control system for PWRs, and for standby liquid control, 

reactor water cleanup, and shutdown cooling systems extending up to the first isolation valve 

outside of containment for BWRs (the shutdown cooling systems for older BWRs). The following 

systems have portions that are classified as Group B quality standard: open-cycle cooling water 

(service water system), closed-cycle cooling water, compressed air, standby liquid control, 

shutdown cooling system (older BWR), control room area ventilation, and auxiliary and radwaste 

area ventilation. Aging management for these portions is reviewed following the guidance in 

Section 3.3. The AMP for the cooling towers is reviewed following the guidance in Section 3.5 for 

“Group 6” structures. 

The responsible review organization is to review the following SLR application AMR and AMP 

items assigned to it, per SRP-SLR Section 1.2: 
3.3-2 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 AMR results not consistent with or not addressed in the GALL-SLR Report 

AMPs 

 Consistent with GALL-SLR Report AMPs 

 Plant-specific AMPs 

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.3.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

3.3.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The AMR and the AMPs applicable to the auxiliary system features are described and evaluated 

in Chapter VII of the GALL-SLR Report. 

The applicant’s subsequent license renewal application (SLRA) should provide sufficient 

information so that the NRC reviewer is able to confirm that the specific SLRA AMR item and the 

associated SLRA AMP are consistent with the cited GALL-SLR Report AMR item. The reviewer 

should then confirm that the SLRA AMR item is consistent with the GALL-SLR Report AMR item 

to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

capable of managing the effects of aging as adequately as the AMP recommended by the 

GALL-SLR Report. 

3.3.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria, defined in Subsection 3.3.2.1, need to be applied first for all of the 

AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR item 

to which the SLRA AMR item is compared identifies that “further evaluation is recommended,” 

then additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.3-1, comparing the “Further Evaluation 
3.3-3 

Recommended” and the “GALL-SLR Item” column, for the AMR items that reference the 

following subsections. 

3.3.2.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be time-limited 

aging analyses (TLAAs), as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). This TLAA is addressed separately in Section 4.3, 

“Metal Fatigue,” or Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses,” of this 

SRP-SLR. For plant-specific cumulative usage factor calculations that are based on stress-based 

input methods, the methods are to be appropriately defined and discussed in the applicable 

TLAAs. 

3.3.2.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

Cracking due to stress corrosion cracking (SCC) and cyclic loading could occur in stainless steel 

(SS) PWR nonregenerative heat exchanger tubing exposed to treated borated water greater than 

60 °C (Celsius) [140 °F (Fahrenheit)] in the chemical and volume control system. The existing 

AMP for monitoring and control of primary water chemistry in PWRs (GALL-SLR Report AMP 

XI.M2, “Water Chemistry”) manages the aging effects of cracking due to SCC. However, control 

of water chemistry does not preclude cracking due to SCC and cyclic loading. Therefore, the 

effectiveness of the water chemistry control program should be verified to ensure that cracking is 

not occurring. If a search of plant-specific operating experience (OE) does not reveal that 

cracking has occurred in nonregenerative heat exchanger tubing, this aging effect can be 

considered to be adequately managed by GALL-SLR Report AMP XI.M2. However, if cracking 

has occurred in nonregenerative heat exchanger tubing, the GALL-SLR Report recommends that 

AMP XI.M21A, “Closed Treated Water Systems,” be evaluated for inclusion of augmented 

requirements to conduct temperature and radioactivity monitoring of the shell side water, and 

where component configuration permits, periodic eddy current testing of tubes. 

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

Cracking due to SCC could occur in indoor or outdoor SS piping, piping components, and tanks 

exposed to any air, condensation, or underground environment when the component is: 

(a) uninsulated, (b) insulated, (c) in the vicinity of insulated components, or (d) in the vicinity of 

potentially transportable halogens. Cracking can occur in environments containing sufficient 

halides (e.g., chlorides) in the presence of moisture. 

Insulated SS components exposed to indoor air, outdoor air, condensation, or underground 

environments are susceptible to SCC if the insulation contains certain contaminants. Leakage of 

fluids through bolted connections (e.g., flanges, valve packing) can result in contaminants present 

in the insulation leaching onto the component surface or the surfaces of other components below 

the component. For outdoor insulated SS components, rain and changing weather conditions can 

result in moisture intrusion into the insulation. 

Plant-specific OE and the condition of SS components are evaluated to determine if prolonged 

exposure to the plant-specific environments has resulted in SCC. SCC in SS components is not 

an aging effect requiring management if (a) plant-specific OE does not reveal a history of SCC 

and (b) a one-time inspection demonstrates that the aging effect is not occurring. 
3.3-4 

In the environment of air-indoor controlled, SCC is only expected to occur as the result of a source 

of moisture and halides. Inspections focus on the most susceptible locations. The applicant 

documents the results of the plant-specific OE review in the license renewal application (LRA). 

The GALL-SLR Report recommends further evaluation of SS piping, piping components, and 

tanks exposed to an air, condensation, or underground environment to determine whether an 

AMP is needed to manage the aging effect of SCC. The GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” describes an acceptable program to demonstrate that SCC is not 

occurring. If SCC is applicable, the following AMPs describe acceptable programs to manage 

loss of material due to SCC: (a) GALL-SLR Report AMP XI.M29, “Outdoor and Large 

Atmospheric Metallic Storage Tanks,” for tanks; (b) GALL-SLR Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” for external surfaces of piping and piping 

components; (c) GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” for 

underground piping, piping components and tanks; and (d) GALL-SLR Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” for internal 

surfaces of components that are not included in other AMPs. The timing of the one-time or 

periodic inspections is consistent with that recommended in the AMP selected by the applicant 

during the development of the SLRA. For example, one-time inspections would be conducted 

between the 50th and 60th year of operation, as recommended by the “detection of aging effects” 

program element in GALL-SLR Report AMP XI.M32. 

The applicant may establish that SCC is not an aging effect requiring management for all 

components, by demonstrating that a barrier coating isolates the component from aggressive 

environments. Acceptable barriers include tightly-adhering coatings that have been demonstrated 

to be impermeable to aqueous solutions and air that contain halides. The GALL-SLR Report AMP 

XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 

and Tanks,” describes an acceptable program to manage the integrity of a barrier coating. 

3.3.2.2.4 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

Loss of material due to pitting and crevice corrosion could occur in indoor or outdoor SS and 

nickel alloy piping, piping components, and tanks exposed to any air, condensation, or 

underground environment when the component is: (a) uninsulated; (b) insulated; (c) in the vicinity 

of insulated components; or (d) in the vicinity of potentially transportable halogens. Loss of 

material due to pitting and crevice corrosion can occur on SS and nickel alloys in environments 

containing sufficient halides (e.g., chlorides) in the presence of moisture. 

Insulated SS and nickel alloy components exposed to air, condensation, or underground 

environments are susceptible to loss of material due to pitting or crevice corrosion if the insulation 

contains certain contaminants. Leakage of fluids through mechanical connections such as bolted 

flanges and valve packing can result in contaminants leaching onto the component surface or 

the surfaces of other components below the component. For outdoor insulated SS and nickel 

alloy components, rain and changing weather conditions can result in moisture intrusion into 

the insulation. 

Plant-specific OE and the condition of SS and nickel alloy components are evaluated to determine 

if prolonged exposure to the plant-specific environments has resulted in pitting or crevice 

corrosion. Loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management for SS and nickel alloy components if (a) plant-specific OE does not reveal a history 

of loss of material due to pitting or crevice corrosion; and (b) a one-time inspection demonstrates 
3.3-5 

that the aging effect is not occurring or is occurring so slowly that it will not affect the intended 

function of the components during the subsequent period of extended operation. The applicant 

documents the results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to 

occur as the result of a source of moisture and halides. Inspections focus on the most 

susceptible locations. 

The GALL-SLR Report recommends further evaluation of SS and nickel alloy piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that loss of material due to pitting and crevice corrosion is not 

occurring at a rate that affects the intended function of the components. If loss of material due to 

pitting or crevice corrosion has occurred and is sufficient to potentially affect the intended function 

of an SSC, the following AMPs describe acceptable programs to manage loss of material due to 

pitting or crevice corrosion: (a) GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric 

Metallic Storage Tanks,” for tanks; (b) GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” for external surfaces of piping and piping components; 

(c) GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground 

piping, piping components and tanks; and (d) GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” for internal surfaces of 

components that are not included in other AMPs. The timing of the one-time or periodic 

inspections is consistent with that recommended in the AMP selected by the applicant during the 

development of the SLRA. For example, one-time inspections would be conducted between the 

50th and 60th year of operation, as recommended by the “detection of aging effects” program 

element in GALL-SLR Report AMP XI.M32. 

The applicant may establish that loss of material due to pitting and crevice corrosion is not an 

aging effect requiring management by demonstrating that a barrier coating isolates the component 

from aggressive environments. Acceptable barriers include tightly-adhering coatings that have 

been demonstrated to be impermeable to aqueous solutions and air that contain halides. GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” describes an acceptable program to manage the integrity of a 

barrier coating. 

3.3.2.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in Branch Technical Position (BTP) IQMB-1 (Appendix A.2 of 

this SRP-SLR.) 

3.3.2.2.6 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.3.2.2.7 Loss of Material Due to Recurring Internal Corrosion 

Recurring internal corrosion can result in the need to augment AMPs beyond the 

recommendations in the GALL-SLR Report. During the search of plant-specific OE conducted 

during the SLRA development, recurring internal corrosion can be identified by the number of 
3.3-6 

occurrences of aging effects and the extent of degradation at each localized corrosion site. This 

further evaluation item is applicable if the search of plant specific OE reveals repetitive 

occurrences. The criteria for recurrence is (a) a 10 year search of plant specific OE reveals the 

aging effect has occurred in three or more refueling outage cycles; or (b) a 5 year search of plant 

specific OE reveals the aging effect has occurred in two or more refueling outage cycles and 

resulted in the component either not meeting plant specific acceptance criteria or experiencing a 

reduction in wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The GALL-SLR Report recommends that GALL-SLR Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” GALL-SLR Report AMP XI.M27, “Fire Water System,” or GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” 

be evaluated for inclusion of augmented requirements to ensure the adequate management of 

any recurring aging effect(s). Alternatively, a plant-specific AMP may be proposed. Potential 

augmented requirements include: alternative examination methods (e.g., volumetric versus 

external visual), augmented inspections (e.g., a greater number of locations, additional locations 

based on risk insights based on susceptibility to aging effect and consequences of failure, a 

greater frequency of inspections), and additional trending parameters and decision points where 

increased inspections would be implemented. 

The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

recurring aging effect before affecting the ability of a component to perform its intended function, 

(b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

parameters will be trended as well as the decision points where increased inspections would be 

implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

change), (d) how inspections of components that are not easily accessed (i.e., buried, 

underground) will be conducted, and (e) how leaks in any involved buried or underground 

components will be identified. 

Plant-specific OE examples should be evaluated to determine if the chosen AMP should be 

augmented even if the thresholds for significance of aging effect or frequency of occurrence of 

aging effect have not been exceeded. For example, during a 10-year search of plant-specific OE, 

two instances of 360 degree 30 percent wall loss occurred at copper alloy to steel joints. Neither 

the significance of the aging effect nor the frequency of occurrence of aging effect threshold has 

been exceeded. Nevertheless, the OE should be evaluated to determine if the AMP that is 

proposed to manage the aging effect is sufficient (e.g., method of inspection, frequency of 

inspection, number of inspections) to provide reasonable assurance that the current licensing 

basis (CLB) intended functions of the component will be met throughout the subsequent period of 

extended operation. While recurring internal corrosion is not as likely in other environments as 

raw water and waste water (e.g., treated water), the aging effect should be addressed in a 

similar manner.

3.3.2.2.8 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

SCC is a form of environmentally assisted cracking which is known to occur in high and moderate 

strength aluminum alloys. The three conditions necessary for SCC to occur in a component are a 

sustained tensile stress, aggressive environment, and material with a susceptible microstructure. 

Cracking due to SCC can be mitigated by eliminating one of the three necessary conditions. For 

the purposes of SLR, acceptance criteria for this further evaluation is being provided for 

demonstrating that the specific material is not susceptible to SCC or an aggressive environment 

is not present. Cracking due to SCC is an aging effect requiring management unless it is 
3.3-7 

demonstrated by the applicant that one of the two necessary conditions discussed below 

is absent. 

Susceptible Material: If the material is not susceptible to SCC then cracking is not an aging effect 

requiring management. The microstructure of an aluminum alloy, of which alloy composition is 

only one factor, is what determines if the alloy is susceptible to SCC. Therefore, determining 

susceptibility based on alloy composition alone is not adequate to conclude whether a particular 

material is susceptible to SCC. The temper, condition, and product form of the alloy is considered 

when assessing if a material is susceptible to SCC. Aluminum alloys that are susceptible to 

SCC include: 

 2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

 5xxx series alloys with a magnesium content of 3.5 weight percent or greater 

 6xxx series alloys in the F temper 

 7xxx series alloys in the F, T5x, or T6x temper 

 2xx.x and 7xx.x series alloys 

 3xx.x series alloys that contain copper 

 5xx.x series alloys with a magnesium content of greater than 8 weight percent 

The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

make the determination is technically substantiated. Tempers have been specifically developed 

to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 

combination which are not susceptible to SCC when used in piping, piping component, and tank 

applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. If it is determined that a 

material is not susceptible to SCC, the SLRA provides the components/locations where it is used, 

alloy composition, temper or condition, product form, and for tempers not addressed above, the 

basis used to determine the alloy is not susceptible and technical information substantiating 

the basis. 

Aggressive Environment: If the environment to which an aluminum alloy is exposed is not 

aggressive, such as dry gas or treated water, then cracking due to SCC will not occur and it is not 

an aging effect requiring management. Aggressive environments that are known to result in 

cracking due to SCC of susceptible aluminum alloys are aqueous solutions, air, condensation, 

and underground locations that contain halides (e.g., chloride). Halide concentrations should be 

considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated aqueous 

solutions and air, such as raw water, waste water, condensation, underground locations, and 

outdoor air, unless demonstrated otherwise. 

Halides could be present on the surface of the aluminum material if the component is 

encapsulated in a material such as insulation or concrete. In a controlled or uncontrolled indoor 

air, condensation, or underground environment, sufficient halide concentrations to cause 

SCC could be present due to secondary sources such as leakage from nearby components 

(e.g., leakage from insulated flanged connections or valve packing). If an aluminum component is 

exposed to a halide-free indoor air environment, not encapsulated in materials containing halides, 

and the exposure to secondary sources of moisture or halides is precluded, cracking due to SCC 

is not expected to occur. The plant-specific configuration can be used to demonstrate that 

exposure to halides will not occur. If it is determined that SCC will not occur because the 

environment is not aggressive, the SLRA provides the components and locations exposed to the 

environment, a description of the environment, basis used to determine the environment is not 

aggressive, and technical information substantiating the basis. The GALL-SLR Report 

AMP XI.M32, “One-Time Inspection,” and a review of plant-specific OE describe an acceptable 
3.3-8 

means to confirm the absence of moisture or halides within the proximity of the aluminum 

component. 

If the environment potentially contains halides, GALL-SLR Report AMP XI.M29, “Outdoor and 

Large Atmospheric Metallic Storage Tanks,” describes an acceptable program to manage 

cracking due to SCC of aluminum tanks. GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” describes an acceptable program to manage cracking 

due to SCC of aluminum piping and piping components. GALL-SLR Report AMP XI.M41, “Buried 

and Underground Piping and Tanks,” describes an acceptable program to manage cracking due 

to SCC of aluminum piping and tanks which are buried or underground. GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components” 

describes an acceptable program to manage cracking due to SCC of aluminum components that 

are not included in other AMPs. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

barriers include tightly-adhering coatings that have been demonstrated to be impermeable to 

aqueous solutions and air that contain halides. GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” 

describes an acceptable program to manage the integrity of a barrier coating for internal or 

external coatings. 

3.3.2.2.9 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

Loss of material due to general (steel only), crevice, or pitting corrosion, and cracking due to SCC 

(SS only) can occur in steel and SS piping and piping components exposed to concrete. 

Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for 

steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through 

the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, 

which can penetrate the protective oxide layer created in the high alkalinity environment, can 

reach the surface of the metal. Carbonation can reduce the pH within concrete. The rate of 

carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability. 

Concrete with low permeability also reduces the potential for the penetration of water. Adequate 

air entrainment improves the ability of the concrete to resist freezing and thawing cycles and 

therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well 

as pitting and crevice corrosion can occur due to halides present in the water that penetrates to 

the surface of the metal. 

If the following conditions are met, loss of material is not considered to be an applicable aging 

effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

(ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) 

as cited in NUREG–1557; (b) plant-specific OE indicates no degradation of the concrete that 

could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

exposed to groundwater. For SS components, loss of material and cracking due to SCC are not 

considered to be applicable aging effects as long as the piping is not potentially exposed to 

groundwater. Where these conditions are not met, loss of material due to general (steel only), 

crevice, or pitting corrosion, and cracking due to SCC (SS only) are identified as applicable aging 

effects. GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes 

an acceptable program to manage these aging effects. 
3.3-9 

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 

environment for a sufficient duration of time. Environments that can result in pitting and/or crevice 

corrosion of aluminum alloys are those that contain halides (e.g., chloride) in the presence of 

moisture. The moisture level and halide concentration in atmospheric and uncontrolled air are 

greatly dependent on geographical location and site-specific conditions. Moisture level and halide 

concentration should be considered high enough to facilitate pitting and/or crevice corrosion of 

aluminum alloys in atmospheric and uncontrolled air, unless demonstrated otherwise. The 

periodic introduction of moisture or halides into an environment from secondary sources should 

also be considered. Leakage of fluids from mechanical connections (e.g., insulated bolted flanges 

and valve packing); onto a component in indoor controlled air is an example of a secondary 

source that should be considered. Halide concentrations should be considered high enough to 

facilitate loss of material of aluminum alloys in untreated aqueous solutions, unless demonstrated 

otherwise. Plant-specific OE and the condition of aluminum alloy components are evaluated to 

determine if prolonged exposure to the plant-specific air, condensation, underground, or water 

environments has resulted in pitting or crevice corrosion. Loss of material due to pitting and 

crevice corrosion is not an aging effect requiring management for aluminum alloys if (a) plantspecific OE does not reveal a history of loss of material due to pitting or crevice corrosion and (b) 

a one-time inspection demonstrates that the aging effect is not occurring or is occurring so slowly 

that it will not affect the intended function of the components. The applicant documents the 

results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to occur 

as the result of a source of moisture and halides. Alloy susceptibility may be considered when 

reviewing OE and interpreting inspection results. Inspections focus on the most susceptible alloys 

and locations. 

The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that the aging effect of loss of material due to pitting and 

crevice corrosion is not occurring at a rate that will affect the intended function of the components. 

If loss of material due to pitting or crevice corrosion has occurred and is sufficient to potentially 

affect the intended function of an SSC, the following AMPs describe acceptable programs to 

manage loss of material due to pitting and crevice corrosion: (i) GALL-SLR Report AMP XI.M29, 

“Outdoor and Large Atmospheric Metallic Storage Tanks,” for tanks; (ii) GALL-SLR Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” for external surfaces of 

piping and piping components; (iii) GALL-SLR Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” for underground piping, piping components and tanks; and (iv) GALL-SLR 

Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components” for internal surfaces of components that are not included in other AMPs. The timing 

of the one-time or periodic inspections is consistent with that recommended in the AMP selected 

by the applicant during the development of the SLRA. For example, one-time inspections would 

be conducted between the 50th and 60th year of operation, as recommended by the “detection of 

aging effects” program element in GALL-SLR Report AMP XI.M32. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent loss of material due to 
3.3-10 

pitting and crevice corrosion. Acceptable barriers include tightly-adhering coatings that have been 

demonstrated to be impermeable to aqueous solutions and air that contain halides. The GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” or equivalent program, describes an acceptable program to 

manage the integrity of a barrier coating. 

3.3.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR) 

3.3.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and are based on the program elements 

of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs credited in the 

SLRA to confirm consistency with the GALL-SLR Report AMPs identified in Chapters X and XI. 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, the 

difference should be reviewed and properly dispositioned. The reviewer should document the 

disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP to 

be declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. 

The reviewer is to confirm both that the enhancement, when implemented, would allow the 

existing SLRA AMP to be consistent with the GALL-SLR Report AMP and also that the applicant 

has a commitment in the FSAR Supplement to implement the enhancement prior to the 

subsequent period of extended operation. The reviewer should document the disposition of 

all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.3.2.5 Final Safety Analysis Report Supplement 

The summary description of the programs and activities for managing the effects of aging for the 

subsequent period of extended operation in the FSAR Supplement should be sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

should contain information associated with the bases for determining that aging effects will be 

managed during the subsequent period of extended operation. The description should also 

contain any future aging management activities, including enhancements and commitments, to be 

completed before the period of extended operation. Table X-01 and Table XI-01 of the 

GALL-SLR Report provide examples of the type of information to be included in the FSAR 

Supplement. Table 3.3-2 lists the programs that are applicable for this SRP-SLR subsection. 
3.3-11 

3.3.3 Review Procedures 

For each area of review, the following review procedures are to be followed. 

3.3.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a re-review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to the GALL-SLR Report in its 

SLRA. In making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects have been addressed based in the staff’s review of industry and 

plant-specific OE. 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review requires the reviewer to confirm 

that the applicant has identified those aging effects for the auxiliary system components that are 

contained in the GALL-SLR Report as applicable to its plant. 

3.3.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Subsection 3.3.3.1 need to be applied first for all of the 

AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to which 

the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.3-1 for the items that reference the 

following subsections. 

3.3.3.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be TLAAs, 

as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Section 4.3 or 4.7 (as applicable) to determine whether the applicant has provided 

a sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria in 

10 CFR 54.21(c)(1)(i), (ii), or (iii). This includes staff’s review of those cumulative usage factor 

analyses that qualify as TLAAs and are based on plant-specific, stress-based 

calculation methods. 

3.3.3.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

The GALL-SLR Report recommends further evaluation of programs to manage cracking due to 

SCC and cyclic loading in the SS nonregenerative heat exchanger tubing in the chemical and 

volume control system (PWR) exposed to treated borated water >60 °C (>140 °F). The water 
3.3-12 

chemistry program relies on monitoring and control of water chemistry to manage cracking due to 

SCC and cyclic loading. The GALL-SLR Report recommends the effectiveness of the chemistry 

control program be verified to ensure that cracking is not occurring. The absence of cracking due 

to SCC and cyclic loading is to be verified. An acceptable verification program is to include 

temperature and radioactivity monitoring of the shell side water, and eddy current testing of tubes. 

The reviewer reviews plant-specific OE to determine whether cracking has occurred in the 

applicant’s nonregenerative heat exchanger tubes. If cracking has occurred, the reviewer reviews 

the applicant’s proposed changes to GALL-SLR Report AMP XI.M21A to determine whether the 

proposed augmented features of the program will be adequate to manage these aging effects. 

3.3.3.2.3 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

The GALL-SLR Report recommends further evaluation to manage cracking due to SCC of SS 

piping, piping components, and tanks exposed to air and underground environments containing 

sufficient halides (e.g., chlorides) and in which condensation is possible. The possibility of 

cracking also extends to components exposed to air which has recently been introduced into 

buildings (i.e., components near intake vents) or where the component is in the vicinity of 

insulated components. 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals SCC in SS alloys, the reviewer determines whether 

an adequate program is credited to manage the aging effect. If the review of plant-specific OE 

reveals that SCC is not applicable, the reviewer verifies that GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that SCC has 

occurred in the outdoor air environment but not the indoor air environment. The applicant could 

further categorize the indoor air locations as those where leakage could impinge on the SS 

component’s surface (e.g., leakage from mechanical connections) and those where there is not a 

potential for leakage. When the applicant chooses to conduct its OE search in this manner, the 

reviewer also is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include leakage from mechanical connections, 

leakage into vaults, insulation containing halides, and outdoor air intrusion. Grouping of 

environments consistent with that described in the detection of aging effects program element of 

GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 
3.3-13 

3.3.3.2.4 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

and crevice corrosion in SS and nickel alloy piping and piping components exposed to any air, 

condensation, or underground environment, when the component is: (a) uninsulated; 

(b) insulated; (c) in the vicinity of insulated components where the presence of sufficient halides 

(e.g., chlorides) and moisture is possible; or (d) in the vicinity of potentially transportable halogens. 

The possibility of pitting and crevice corrosion also extends to indoor components located in close 

proximity to sources of outdoor air (e.g., components near intake vents). 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals loss of material due to pitting or crevice corrosion in 

SS and nickel alloys, the reviewer determines whether an adequate program is credited to 

manage the aging effect. If the review of plant-specific OE reveals that loss of material due to 

pitting and crevice corrosion is not applicable, the reviewer verifies that GALL-SLR Report 

AMP XI.M32, “One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that loss of material 

due to pitting and crevice corrosion has occurred in the outdoor air environment but not the indoor 

air environment. The applicant could further categorize the indoor air locations as those where 

leakage could impinge on the SS and nickel alloy component’s surface (e.g., leakage from 

mechanical connections) and those where there is not a potential for leakage. When the applicant 

chooses to conduct its OE search in this manner, the reviewer is to also confirm that the applicant 

has adequately addressed the potential for the periodic introduction of either moisture or halides 

from secondary sources. Secondary sources of moisture or halides should be considered for all 

environments including indoor conditioned air. Typical secondary sources of moisture or halides 

include: leakage from mechanical connections; leakage into vaults; insulation containing halides; 

and outdoor air intrusion. Grouping of environments consistent with that described in the 

detection of aging effects program element of GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.3.3.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMPs for SLR should contain the elements of corrective actions, the confirmation 

process, and administrative controls. Safety-related components are covered by 10 CFR Part 50, 

Appendix B, which is adequate to address these program elements. However, Appendix B does 

not apply to nonsafety-related components that are subject to an AMR for SLR. Nevertheless, the 

applicant has the option to expand the scope of its 10 CFR Part 50, Appendix B program to 

include these components and address the associated program elements. If the applicant 

chooses this option, the reviewer verifies that the applicant has documented such a commitment 

in the FSAR Supplement. If the applicant chooses alternative means, the branch responsible 
3.3-14 

for quality assurance should be requested to review the applicant’s proposal on a 

case-by-case basis. 

3.3.3.2.6 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to 

ensure that the AMPs are effective to manage the aging effects for which they are created. The 

AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined 

through the evaluation of OE that the effects of aging may not be adequately managed. 

Additional information is in Appendix A.4, “Operating Experience for Aging Management 

Programs” of this SRP-SLR. 

3.3.3.2.7 Loss of Material Due to Recurring Internal Corrosion 

The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

aging effects. The reviewer conducts an independent review of plant-specific OE to determine 

whether the plant is currently experiencing recurring internal corrosion. This further evaluation 

item is applicable if the search of plant-specific OE reveals repetitive occurrences. The criteria for 

recurrence is (a) a 10-year search of plant specific OE reveals the aging effect has occurred in 

three or more refueling outage cycles; or (b) a 5-year search of plant specific OE reveals the 

aging effect has occurred in two or more refueling outage cycles as a result of which the 

component either did not meet plant-specific acceptance criteria or experienced a reduction in 

wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The reviewer should evaluate plant-specific OE examples to determine if the chosen AMP should 

be augmented. For example, during a 10-year search of plant-specific OE, two instances of 

360 degree 30 percent wall loss occurred at copper alloy to steel joints. Neither the significance 

of the aging effect nor the frequency of occurrence of aging effect threshold has been exceeded. 

Nevertheless, the OE should be evaluated to determine if the AMP that is proposed to manage 

the aging effect is sufficient (e.g., method of inspection, frequency of inspection, number of 

inspections) to provide reasonable assurance that the CLB intended functions of the component 

will be met throughout the subsequent period of extended operation. 

The reviewer determines whether a proposed program is adequate to manage recurring internal 

corrosion by evaluating the proposed AMP against the criteria in SRP-SLR Section 3.3.2.2.7. 

3.3.3.2.8 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

The GALL-SLR Report recommends the further evaluation of aluminum components (i.e., piping, 

piping components, and tanks) exposed to air, condensation, underground or aqueous solutions 

that contain halides to manage cracking due to SCC. The reviewer must first determine if 

cracking due to SCC is applicable and requires aging management. Cracking is to be considered 

applicable unless it is demonstrated that one of the two acceptance criteria are met by 

demonstrating that an aggressive environment is not present or the specific material is not 

susceptible, as discussed previously in Section 3.3.2.2.8. Additionally, guidance is also provided 

on the review of the third condition necessary for SCC to occur, a sustained tensile stress. Each 

of three conditions is evaluated based on the review procedures below. 
3.3-15 

If the material used to fabricate the component being evaluated is not susceptible to SCC then 

cracking due to SCC is not an aging effect requiring management. When determining if an 

aluminum alloy is susceptible to SCC the reviewer is to verify the materials: (a) alloy composition, 

(b) condition or temper, and (c) product form. Additionally, if the material was produced using a 

process specifically developed to provide a SCC resistant microstructure then the reviewer will 

consider the effects of this processing in the review. Once the material information has been 

established the reviewer is to evaluate the technical justification used to substantiate that the 

material is not susceptible to SCC when exposed to an aggressive environment and sustained 

tensile stress. The reviewer will evaluate all documentation and references used by the applicant 

as part of a technical justification. 

If the environment to which an aluminum alloy is exposed is not aggressive, such as dry gas, or 

treated water, then cracking due to SCC is not an aging effect requiring management. The 

environments cited in the AMR line items in the GALL-SLR Report that reference this further 

evaluation are considered to be aggressive and potentially containing halide concentrations that 

facilitate SCC of aluminum alloys. The reviewer is to verify that components are not also 

periodically exposed to nontypical environments that would be categorized as aggressive, such as 

secondary sources of moisture or halides, including outdoor air which has recently been 

introduced into a building and the leakage/seepage of untreated aqueous solutions into a building 

or underground vault. Controlled indoor air is not considered aggressive unless secondary 

sources of moisture or halides are present. When applicable, the staff reviews the basis for the 

applicant’s claim that the plant configuration precludes the potential presence of secondary 

sources of moisture or halides. Using information provided by the applicant, the reviewer will also 

evaluate the chemical composition of applicable encapsulating materials (e.g., concrete, 

insulation) for halides. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

If the sustained tensile stress being experienced by a component is below the SCC threshold 

value, then cracking is not an aging effect requiring management. Many aluminum alloys do not 

have a true SCC threshold stress, although a practical SCC threshold value can be determined 

based on the material, service environment, and duration of intended function. The basis for the 

SCC threshold value is to be evaluated to determine its applicability. The magnitude of the 

maximum tensile service stress (applied and residual) experienced by the component is to be 

evaluated to verify that the stress levels are bounded by the SCC threshold value. 

The information necessary to determine if SCC is applicable based on the sustained service 

stress is often not readily available. The SCC threshold stress level is dependent on both the 

alloy (e.g., chemical composition, processing history, and microstructure) and service 

environment. Furthermore, the magnitude and state of the residual stress sustained by a 

component is typically not fully characterized. The reviewer must determine the adequacy of both 

the SCC threshold value being used by the applicant and the magnitude of the tensile stress 

being experienced by the component. The evaluation of the SCC threshold value includes the 

verification that the: (a) test method used to establish the threshold value is standardized and 

recognized by the industry, (b) data are statistically significant or conservative, and (c) data are for 

a relevant alloy, temper, product form, and environment. The evaluation of the tensile stress 
3.3-16 

being experienced by the component includes the verification that the stress analysis accounts for 

(a) all applied and residual stresses and (b) stress riser that can initiate SCC cracks, such as 

corrosion pits and fabrication defects. 

Documentation that may assist the reviewer in determining if cracking due to SCC is applicable 

and requires aging management include: (a) component drawings, (b) applicable codes 

or specifications used in the design, fabrication, and installation of the component, 

(c) material-specific material certification data and lot release data, (d) maintenance records, and 

(e) plant-specific OE. 

If it is determined that cracking due to SCC is applicable the reviewer is to evaluate the applicants 

proposed AMP to ensure that cracking is adequately managed so that the component’s intended 

functions will be maintained consistent with the CLB for the subsequent period of extended 

operation. The GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric Metallic 

Storage Tanks,” describes an acceptable program to manage cracking due to SCC of aluminum 

tanks. The GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” describes an acceptable program to manage cracking due to SCC of aluminum 

piping and piping components. The GALL-SLR Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” describes an acceptable program to manage cracking due to SCC of 

aluminum piping and tanks which are buried or underground. The GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components” 

describes an acceptable program to manage cracking due to SCC of aluminum components that 

are not included in other AMPs.

3.3.3.2.9 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

The GALL-SLR Report recommends that for steel piping and piping components exposed to 

concrete, if the following conditions are met, loss of material is not considered to be an applicable 

aging effect for steel: (a) 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; 

(b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of 

water to the metal surface; and (c) the piping is not potentially exposed to groundwater. For SS 

piping and piping components, loss of material and cracking due to SCC are not considered to be 

applicable aging effects as long as the piping is not potentially exposed to groundwater. Where 

these conditions are not met, loss of material due to general (steel only), crevice, or pitting 

corrosion and cracking due to SCC (SS only) are identified as applicable aging effects. 

GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes an 

acceptable program to manage these aging effects. 

The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-tocement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

reviewer should evaluate plant-specific OE to determine whether concrete degradation sufficient 

to allow water intrusion has occurred. 

3.3.3.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

The GALL-SLR Report recommends a further evaluation to determine whether an AMP is needed 

to manage loss of material due to pitting and crevice corrosion of aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 
3.3-17 

environment. The reviewer is to conduct an independent assessment of plant-specific OE during 

the AMP audit to confirm that the applicant’s evaluation of its OE is adequate. 

The reviewer is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include leakage from mechanical connections, 

leakage into vaults, insulation containing halides, and outdoor air intrusion. Grouping of 

environments consistent with that found in the GALL-SLR Report Section IX.D is appropriate. 

The grouping of OE search results based on environmental factors or plant configuration may be 

appropriate. The reviewer is to verify that the considerations given to groupings based on 

environmental factors and/or plant configuration have a substantiated technical basis. 

Components in the vicinity of secondary sources of moisture or halides may be treated as a 

separate population when performing inspections and interpreting results due to plant-specific 

configurations. 

The grouping of alloys based on relative susceptibility to loss of material may also be appropriate. 

The reviewer is to verify that the considerations given to alloy susceptibility and/or grouping have 

a substantiated technical basis. The high strength heat treatable aluminum alloys (2xxx and 7xxx 

series) may be treated as a separate population when performing inspections and interpreting 

results due to their relatively lower corrosion resistance. The relative susceptibility of moderate 

and lower strength alloys varies based on composition (primarily weight percent Cu, Mg, and Fe) 

and temper designation. 

The reviewer is to determine whether an adequate program is credited to manage the aging effect 

if the OE reveals that loss of material is applicable or the applicant elects to manage loss of 

material due to pitting or crevice corrosion. The reviewer is to verify that the SLRA cites the use of 

GALL-SLR Report AMP XI.M32, “One-Time Inspection,” for all aluminum piping, piping 

components, and tanks exposed to air, condensation, or underground environments when 

confirming that the aging effect is not applicable based on the OE evaluation. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.3.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging effects, 

listed the appropriate combination of materials and environments, and has credited AMPs that will 

adequately manage the aging effects. The AMP credited by the applicant could be an AMP that is 

described and evaluated in the GALL-SLR Report or a plant-specific program. Review 

procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 
3.3-18 

3.3.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the auxiliary systems components are summarized in Table 3.3-1 of this SRP-SLR. 

The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR Report, 

Chapter VII, presenting detailed information summarized by this row. 

3.3.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in its FSAR Supplement information on 

aging management of the auxiliary systems. Table 3.3-2 lists the AMPs that are applicable for 

this SRP-SLR subsection. The reviewer also confirms that the applicant has provided information 

for Subsection 3.3.3.3, “Aging Management Review Results Not Consistent With or Not 

Addressed in the Generic Aging Lessons Learned for Subsequent License Renewal Report.” 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

3.3.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has demonstrated that the aging effects associated with the auxiliary 

systems components will be adequately managed so that the intended functions 

will be maintained consistent with the CLB for the subsequent period of extended 

operation, as required by 10 CFR 54.21(a)(3). 
3.3-19 

The NRC staff also reviewed the applicable FSAR Supplement program summaries and 

concludes that they adequately describe the AMPs credited for managing aging of the 

auxiliary systems, as required by 10 CFR 54.21(d). 

3.3.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.3.6 References 

1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML070630046. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 2007. 

2. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. ADAMS Accession 

No. ML051860406. Washington, DC: Nuclear Energy Institute. June 2005. 

3. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components.” ASME Boiler and Pressure Vessel Code, 2004 Edition. New York, 

New York: The American Society of Mechanical Engineers. 

4. ASTM International. “Standard Test Method for Water in Petroleum Products and 

Bituminous Materials by Distillation.” D95-83. West Conshohocken, Pennsylvania: 

American Society for Testing and Materials. 1990. 

5. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License Renewal.” 

Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 

6. ACI. ACI Standard 318-95, “Building Code Requirements for Reinforced Concrete and 

Commentary.” Farmington Hills, Michigan: American Concrete Institute. 1995. 

7. ACI. ACI Standard 349-85, “Code Requirements for Nuclear Safety-Related Concrete 

Structures.” Farmington Hills, Michigan: American Concrete Institute. 1985. 

8. ANSI. ANSI Standard H35.1/H35.1M, “Alloy and Temper Designation Systems for 

Aluminum.” New York, New York: American National Standards Institute, Inc. 2013. 

9. ASM. Corrosion of Aluminum and Aluminum Alloys. J. R. Davis, ed. Materials Park, 

Ohio: ASM International. 1999. 

10. NRL. Stress-Corrosion Cracking in High Strength Steels and in Titanium and Aluminum 

Alloys. B. F. Brown, ed. Washington, DC: Naval Research Laboratory. 1972. 
3.3-20 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 001 BWR/PWR Steel cranes: bridges, 

structural members, structural components exposed to any environment 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.7 "Other Plant-Specific TLAAs" 

Yes (SRP-SLR Section 3.3.2.2.1) 

VII.B.A-06 

M 002 BWR/PWR Stainless steel, steel 

heat exchanger components and tubes, piping, piping components exposed to any environment 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.3.2.2.1) 

VII.E1.A-100 VII.E1.A-34 VII.E1.A-57 VII.E3.A-34 VII.E3.A-62 VII.E4.A-62 

M 003 PWR Stainless steel heat 

exchanger tubing, non-regenerative exposed to treated borated water >60°C (>140°F) 

Cracking due to SCC; cyclic loading 

AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.3.2.2.2) 

VII.E1.A-69 

N 003a PWR Stainless steel heat 

exchanger tubing, non-regenerative exposed to treated borated water >60°C (>140°F) 

Cracking due to SCC; cyclic loading 

AMP XI.M2, "Water Chemistry," and AMP XI.M21A, "Closed Treated Water Systems" 

Yes (SRP-SLR Section 3.3.2.2.2) 

VII.E1.A-69a 

M 004 BWR/PWR Stainless steel piping, 

piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.C1.AP-209aVII.C1.AP-209bVII.C1.AP-209cVII.C1.AP-209dVII.C2.AP-209aVII.C2.AP-209bVII.C2.AP-209cVII.C2.AP-209dVII.C3.AP-209aVII.C3.AP-209bVII.C3.AP-209cVII.C3.AP-209dVII.D.AP-209a VII.D.AP-209b VII.D.AP-209c 
3.3-21 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

"Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

VII.D.AP-209d VII.E1.AP-209aVII.E1.AP-209bVII.E1.AP-209cVII.E1.AP-209dVII.E4.AP-209aVII.E4.AP-209bVII.E4.AP-209cVII.E4.AP-209dVII.F1.AP-209aVII.F1.AP-209bVII.F1.AP-209cVII.F1.AP-209dVII.F2.AP-209aVII.F2.AP-209bVII.F2.AP-209cVII.F2.AP-209dVII.F3.AP-209aVII.F3.AP-209bVII.F3.AP-209cVII.F3.AP-209dVII.F4.AP-209aVII.F4.AP-209bVII.F4.AP-209cVII.F4.AP-209dVII.G.AP-209a VII.G.AP-209b VII.G.AP-209c VII.G.AP-209d VII.H1.AP-209aVII.H1.AP-209bVII.H1.AP-209cVII.H1.AP-209dVII.H2.AP-209aVII.H2.AP-209bVII.H2.AP-209cVII.H2.AP-209d 

D 005 
3.3-22 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 006 BWR/PWR Stainless steel, nickel 

alloy piping, piping components exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.C1.AP-221aVII.C1.AP-221bVII.C1.AP-221cVII.C1.AP-221dVII.C2.AP-221aVII.C2.AP-221bVII.C2.AP-221cVII.C2.AP-221dVII.C3.AP-221aVII.C3.AP-221bVII.C3.AP-221cVII.C3.AP-221dVII.D.AP-221a VII.D.AP-221b VII.D.AP-221c VII.D.AP-221d VII.E1.AP-221aVII.E1.AP-221bVII.E1.AP-221cVII.E1.AP-221dVII.E4.AP-221aVII.E4.AP-221bVII.E4.AP-221cVII.E4.AP-221dVII.F1.AP-221aVII.F1.AP-221bVII.F1.AP-221cVII.F1.AP-221dVII.F2.AP-221aVII.F2.AP-221bVII.F2.AP-221cVII.F2.AP-221dVII.F3.AP-221aVII.F3.AP-221bVII.F3.AP-221cVII.F3.AP-221dVII.F4.AP-221aVII.F4.AP-221bVII.F4.AP-221c
3.3-23 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

VII.F4.AP-221dVII.G.AP-221a VII.G.AP-221b VII.G.AP-221c VII.G.AP-221d VII.H1.AP-221aVII.H1.AP-221bVII.H1.AP-221cVII.H1.AP-221dVII.H2.AP-221aVII.H2.AP-221bVII.H2.AP-221cVII.H2.AP-221d 

 007 PWR Stainless steel highpressure pump, 

casing exposed to treated borated water 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No VII.E1.AP-115 

 008 PWR Stainless steel heat 

exchanger components and tubes exposed to treated borated water >60°C (>140°F) 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No VII.E1.AP-119 

M 009 PWR Steel, copper alloy 

(>15% Zn) external surfaces, piping, piping components exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No VII.I.A-79 

VII.I.AP-66 

M 010 BWR/PWR High-strength steel 

closure bolting exposed to air, soil, underground 

Cracking due to SCC; cyclic loading 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-04 

D 011 
3.3-24 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 012 BWR/PWR Steel; stainless steel, 

nickel alloy closure bolting exposed to air – indoor uncontrolled, air – outdoor, condensation 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-03 

D 013 D 014 M 015 BWR/PWR Metallic closure 

bolting exposed to any environment, soil, underground 

Loss of preload due to thermal effects, gasket creep, self-loosening 

AMP XI.M18, "Bolting Integrity" 

No VII.I.AP-124 

M 016 BWR Stainless steel piping, 

piping components outboard the second containment isolation valves with a diameter ≥4 inches nominal pipe size exposed to treated water >93°C (>200°F) 

Cracking due to SCC, IGSCC 

AMP XI.M2, "Water Chemistry," and AMP XI.M25, "BWR Reactor Water Cleanup System" 

No VII.E3.AP-283 

 017 BWR/PWR Stainless steel heat 

exchanger tubes exposed to treated water, treated borated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-139 

VII.A3.A-101 VII.E1.A-101 

M 018 BWR/PWR Stainless steel highpressure pump 

casing, piping, piping components, tanks exposed to treated borated water >60°C (>140°F), sodium pentaborate solution >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E1.AP-114 

VII.E2.AP-181 
3.3-25 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 019 BWR Stainless steel 

regenerative heat exchanger components exposed to treated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.AP-120 

 020 BWR/PWR 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) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One Time Inspection" 

No VII.E1.AP-118 

VII.E3.AP-112 

M 021 BWR Steel piping, piping 

components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.AP-106 

VII.E4.AP-106 

M 022 BWR Copper alloy piping, 

piping components exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-140 

VII.E3.AP-140 VII.E4.AP-140 

D 023 D 024 M 025 BWR/PWR Aluminum piping, 

piping components exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-130 

VII.C2.AP-130 VII.E3.AP-130 VII.E4.AP-130 VII.H2.AP-130 

M 026 BWR Steel (with stainless 

steel cladding) piping, piping components exposed to treated water 

Loss of material due to general (only after cladding degradation), pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-108 
3.3-26 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 027 BWR Stainless steel heat 

exchanger tubes exposed to treated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One Time Inspection" 

No VII.E3.AP-139 

M 028 PWR Stainless steel piping, 

piping components, tanks exposed to treated borated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E1.AP-82 

D 029 M 030 BWR/PWR Concrete, concrete 

cylinder piping, reinforced concrete, asbestos cement, cementitious piping, piping components exposed to raw water 

Cracking due to chemical reaction, weathering, settlement, or corrosion of reinforcement (reinforced concrete only); loss of material due to delamination, exfoliation, spalling, popout, scaling, or cavitation; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-250 

M 030a BWR/PWR Fiberglass, HDPE 

piping, piping components exposed to raw water 

Cracking, blistering, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-238 

VII.C1.AP-239 

D 031 D 032 D 032a D 033 M 034 BWR/PWR Nickel alloy, copper 

alloy piping, piping components exposed to raw water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-196 

VII.C1.AP-206 VII.C3.AP-195 VII.C3.AP-206 VII.H2.AP-193 

D 035 D 036 
3.3-27 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 037 BWR/PWR Steel piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-194 

VII.C3.AP-194 VII.H2.AP-194 

M 038 BWR/PWR Copper alloy, steel 

heat exchanger components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-179 

VII.C1.AP-183 

D 039 M 040 BWR/PWR Stainless steel piping, 

piping components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.A-54 

VII.C3.A-53 VII.H2.AP-55 

D 041 M 042 BWR/PWR Copper alloy, titanium, 

stainless steel heat exchanger tubes exposed to raw water, raw water (potable), treated water 

Cracking due to SCC (titanium only), reduction of heat transfer due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.AP-187 

VII.C3.AP-187 VII.G.AP-187 VII.H2.AP-187 

M 043 BWR/PWR Stainless steel piping, 

piping components exposed to closedcycle cooling water >60°C (>140°F) 

Cracking due to SCC AMP XI.M21A, 

"Closed Treated Water Systems" 

No VII.C2.AP-186 

VII.E3.AP-186 VII.E4.AP-186 

 044 BWR/PWR Stainless steel; steel 

with stainless steel cladding heat exchanger components exposed to closed-cycle cooling water >60°C (>140°F) 

Cracking due to SCC AMP XI.M21A, 

"Closed Treated Water Systems" 

No VII.E3.AP-192 
3.3-28 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 045 BWR/PWR Steel piping, piping 

components, tanks exposed to closedcycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-202 

VII.F1.AP-202 VII.F2.AP-202 VII.F3.AP-202 VII.F4.AP-202 VII.H2.AP-202 

M 046 BWR/PWR Steel, copper alloy 

heat exchanger components, piping, piping components exposed to closedcycle cooling water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.A3.AP-189 

VII.A3.AP-199 VII.A4.AP-189 VII.A4.AP-199 VII.C2.AP-189 VII.C2.AP-199 VII.E1.AP-189 VII.E1.AP-199 VII.E1.AP-203 VII.E3.AP-189 VII.E3.AP-199 VII.E4.AP-189 VII.E4.AP-199 VII.F1.AP-189 VII.F1.AP-199 VII.F1.AP-203 VII.F2.AP-189 VII.F2.AP-199 VII.F3.AP-189 VII.F3.AP-199 VII.F3.AP-203 VII.F4.AP-189 VII.F4.AP-199 VII.H1.AP-199 VII.H2.AP-199 

M 047 BWR Stainless steel; steel 

with stainless steel cladding heat exchanger components exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.E3.AP-191 

VII.E4.AP-191 
3.3-29 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 048 BWR/PWR Aluminum piping, 

piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-254 

VII.H2.AP-255 

M 049 BWR/PWR Stainless steel piping, 

piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-52 

M 050 BWR/PWR Stainless steel, copper 

alloy, steel heat exchanger tubes exposed to closedcycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-188 

VII.C2.AP-205 VII.E3.AP-188 VII.E4.AP-188 VII.F1.AP-204 VII.F1.AP-205 VII.F2.AP-204 VII.F2.AP-205 VII.F3.AP-204 VII.F3.AP-205 VII.F4.AP-204 VII.F4.AP-205 

 051 BWR/PWR Boraflex spent fuel 

storage racks: neutron-absorbing sheets (PWR), spent fuel storage racks: neutron-absorbing sheets (BWR) exposed to treated borated water, treated water 

Reduction of neutronabsorbing capacity due to boraflex degradation 

AMP XI.M22, "Boraflex Monitoring" 

No VII.A2.A-86 

VII.A2.A-87 

M 052 BWR/PWR Steel cranes: rails, 

bridges, structural members, structural components exposed to air 

Loss of material due to general corrosion, wear, deformation, cracking 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 

No VII.B.A-07 

D 053 
3.3-30 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

D 054 M 055 BWR/PWR Steel piping, piping 

components, tanks exposed to condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.D.A-26 

VII.E5.A-26 VII.F1.A-26 VII.F2.A-26 VII.F3.A-26 VII.F4.A-26 VII.H2.A-26 

D 056 M 057 BWR/PWR Elastomer fire barrier 

penetration seals exposed to air, condensation 

Hardening, loss of strength, shrinkage due to elastomer degradation 

AMP XI.M26, "Fire Protection" 

No VII.G.A-19 

M 058 BWR/PWR Steel halon/carbon 

dioxide fire suppression system piping, piping components exposed to air – indoor uncontrolled, air – outdoor, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M26, "Fire Protection" 

No VII.G.AP-150 

M 059 BWR/PWR Steel fire rated doors 

exposed to air 

Loss of material due to wear AMP XI.M26, 

"Fire Protection" 

No VII.G.A-21 

M 060 BWR/PWR Reinforced concrete 

structural fire barriers: walls, ceilings and floors exposed to air 

Cracking due to chemical reaction, weathering, settlement, or corrosion of reinforcement; loss of material due to delamination, exfoliation, spalling, popout, or scaling 

AMP XI.M26, "Fire Protection," and AMP XI.S6, "Structures Monitoring" 

No VII.G.A-90 

D 061 D 062 M 063 BWR/PWR Steel fire hydrants 

exposed to air – outdoor, raw water, raw water (potable), treated water 

Loss of material due to general, pitting, crevice corrosion; flow blockage due to fouling (raw water, raw water (potable) only) 

AMP XI.M27, "Fire Water System" 

No VII.G.AP-149 
3.3-31 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 064 BWR/PWR Steel, copper alloy 

piping, piping components exposed to raw water, treated water, raw water (potable) 

Loss of material due to general (steel; copper alloy in raw water and raw water (potable) only), pitting, crevice corrosion, MIC; flow blockage due to fouling (raw water; raw water (potable) for steel only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-33 

VII.G.AP-197 

M 065 BWR/PWR Aluminum piping, 

piping components exposed to raw water, treated water, raw water (potable) 

Loss of material due to pitting, crevice corrosion; flow blockage due to fouling (raw water only) 

AMP XI.M27, "Fire Water System" 

No VII.G.AP-180 

M 066 BWR/PWR Stainless steel piping, 

piping components exposed to raw water, treated water, raw water (potable) 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling (raw water only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-55 

D 067 D 068 M 069 BWR/PWR Copper alloy piping, 

piping components exposed to fuel oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection," or AMP XI.M30, "Fuel Oil Chemistry" 

No VII.G.AP-132 

VII.G.AP-132a VII.H1.AP-132 VII.H1.AP-132aVII.H2.AP-132 VII.H2.AP-132a 

M 070 BWR/PWR Steel piping, piping 

components, tanks exposed to fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection," or AMP XI.M30, "Fuel Oil Chemistry" 

No VII.H1.AP-105 

VII.H1.AP-105aVII.H2.AP-105 VII.H2.AP-105aVII.G.AP-234 VII.G.AP-234a 
3.3-32 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 071 BWR/PWR Stainless steel, 

aluminum piping, piping components exposed to fuel oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection," or AMP XI.M30, "Fuel Oil Chemistry" 

No VII.G.AP-129 

VII.G.AP-129a VII.G.AP-136 VII.G.AP-136a VII.H1.AP-129 VII.H1.AP-129aVII.H1.AP-136 VII.H1.AP-136aVII.H2.AP-129 VII.H2.AP-129aVII.H2.AP-136 VII.H2.AP-136a 

M 072 BWR/PWR Gray cast iron, ductile 

iron, copper alloy (>15% Zn or >8% Al) piping, piping components, heat exchanger components exposed to treated water, closed-cycle cooling water, soil, raw water, raw water (potable), waste water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VII.A3.AP-31 

VII.A3.AP-43 VII.A4.AP-31 VII.A4.AP-32 VII.A4.AP-43 VII.C1.A-02 VII.C1.A-47 VII.C1.A-51 VII.C1.A-66 VII.C2.A-50 VII.C2.AP-31 VII.C2.AP-32 VII.C2.AP-43 VII.C3.A-02 VII.C3.A-47 VII.C3.A-51 VII.E1.AP-31 VII.E1.AP-43 VII.E1.AP-65 VII.E3.AP-31 VII.E3.AP-32 VII.E3.AP-43 VII.E4.AP-31 VII.E4.AP-32 VII.E4.AP-43 VII.E5.A-547 
3.3-33 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

VII.E5.A-724 VII.F1.AP-31 VII.F1.AP-43 VII.F1.AP-65 VII.F2.AP-31 VII.F2.AP-43 VII.F3.A-50 VII.F3.AP-43 VII.F3.AP-65 VII.F4.AP-31 VII.F4.AP-43 VII.G.A-02 VII.G.A-47 VII.G.A-51 VII.G.AP-31 VII.H1.A-02 VII.H1.AP-43 VII.H2.A-02 VII.H2.A-47 VII.H2.A-51 VII.H2.AP-43 

M 073 BWR/PWR Concrete, concrete 

cylinder piping, reinforced concrete, asbestos cement, cementitious piping, piping components exposed to air – outdoor 

Cracking due to chemical reaction, weathering, or corrosion of reinforcement (reinforced concrete only); loss of material due to delamination, exfoliation, spalling, popout, or scaling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.AP-253 

D 074 D 075 M 076 BWR/PWR Elastomer piping, 

piping components, ducting, ducting components, seals exposed to air, condensation 

Hardening or loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.AP-102 

D 077 
3.3-34 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 078 BWR/PWR Steel external 

surfaces exposed to air – indoor uncontrolled, air – outdoor, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-77 

D 079 M 080 BWR/PWR Steel heat exchanger 

components, piping, piping components exposed to air – indoor uncontrolled, air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-24 

VII.I.AP-40 VII.I.AP-41 

D 081 M 082 BWR/PWR Elastomer, fiberglass 

piping, piping components, ducting, ducting components, seals exposed to air 

Loss of material due to wear AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-719 

VII.I.AP-113 

M 083 BWR/PWR Stainless steel diesel 

engine exhaust piping, piping components exposed to diesel exhaust 

Cracking due to SCC AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.H2.AP-128 
3.3-35 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 085 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, condensation, closedcycle cooling water, treated borated water, treated water, raw water, raw water (potable), waste water, gas, fuel oil, lubricating oil 

Hardening or loss of strength due to elastomer degradation; flow blockage due to fouling (raw water, waste water only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.A3.AP-100 

VII.A4.AP-101 VII.C1.AP-75 VII.C2.AP-259 VII.D.A-729 VII.E1.A-504 VII.E2.A-504 VII.E3.A-504 VII.E4.A-504 VII.E5.A-504 VII.E5.A-728 VII.F1.A-504 VII.F2.A-504 VII.F3.A-504 VII.F4.A-504 VII.G.A-504 VII.G.A-729 VII.G.AP-75 VII.H1.A-660 VII.H2.A-677 

D 086 M 088 BWR/PWR Steel; stainless steel 

piping, piping components, diesel engine exhaust exposed to raw water (potable), diesel exhaust 

Loss of material due to general (steel only), pitting, crevice corrosion, flow blockage due to fouling (steel only for raw water (potable) environment) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-270 

VII.H2.AP-104 

M 089 BWR/PWR Steel piping, piping 

components exposed to condensation (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.AP-143 

M 090 BWR/PWR Steel ducting, ducting 

components (internal surfaces) exposed to condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (for drip pans and drain lines only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.A-08 

VII.F2.A-08 VII.F3.A-08 VII.F4.A-08 
3.3-36 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 091 BWR/PWR Steel piping, piping 

components, heat exchanger components, tanks exposed to waste water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-281 

D 092 M 093 BWR/PWR Copper alloy piping, 

piping components exposed to raw water (potable) 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-271 

M 094 BWR/PWR Stainless steel 

ducting, ducting components exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.F1.AP-99a VII.F2.AP-99a VII.F3.AP-99a VII.F4.AP-99a VII.F1.AP-99b VII.F2.AP-99b VII.F3.AP-99b VII.F4.AP-99b VII.F1.AP-99c VII.F2.AP-99c VII.F3.AP-99c VII.F4.AP-99c 
3.3-37 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 094a BWR/PWR Stainless steel 

ducting, ducting components exposed to air, condensation 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.F1.A-781a VII.F2.A-781a VII.F3.A-781a VII.F4.A-781a VII.F1.A-781b VII.F2.A-781b VII.F3.A-781b VII.F4.A-781b VII.F1.A-781c VII.F2.A-781c VII.F3.A-781c VII.F4.A-781c 

M 095 BWR/PWR Copper alloy, stainless 

steel, nickel alloy piping, piping components, heat exchanger components, tanks exposed to waste water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-272 

VII.E5.AP-275 VII.E5.AP-276 VII.E5.AP-278 VII.E5.AP-279 

M 096 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, raw water, raw water (potable), treated water, waste water 

Loss of material due to wear; flow blockage due to fouling (raw water, waste water only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.AP-76 

VII.E5.A-550 VII.F1.AP-103 VII.F2.AP-103 VII.F3.AP-103 VII.F4.AP-103 VII.G.AP-76 

N 096a BWR/PWR Steel, aluminum, 

copper alloy, stainless steel, titanium heat exchanger tubes internal to components exposed to air, condensation (external) 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-419 

VII.F1.A-419 VII.F2.A-419 VII.F3.A-419 VII.F4.A-419 
3.3-38 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 096b BWR/PWR Steel heat exchanger 

components exposed to condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.C1.A-417 

VII.F1.A-417 VII.F2.A-417 VII.F3.A-417 VII.F4.A-417 

M 097 BWR/PWR Steel piping, piping 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-127 

VII.C2.AP-127 VII.E1.AP-127 VII.E4.AP-127 VII.F1.AP-127 VII.F2.AP-127 VII.F3.AP-127 VII.F4.AP-127 VII.G.AP-127 VII.H2.AP-127 

M 098 BWR/PWR Steel heat exchanger 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.H2.AP-131 

M 099 BWR/PWR Copper alloy, 

aluminum piping, piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC (copper alloy only) 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-133 

VII.C2.AP-133 VII.E1.AP-133 VII.E4.AP-133 VII.G.AP-133 VII.G.AP-162 VII.H2.AP-133 VII.H2.AP-162 

M 100 BWR/PWR Stainless steel piping, 

piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-138 

VII.C2.AP-138 VII.E1.AP-138 VII.E4.AP-138 VII.G.AP-138 VII.H2.AP-138 
3.3-39 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 101 BWR/PWR Aluminum heat 

exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.H2.AP-154 

 102 BWR/PWR Boral®; boron steel, 

and other materials (excluding Boraflex) spent fuel storage racks: neutronabsorbing sheets (PWR), spent fuel storage racks: neutron-absorbing sheets (BWR) exposed to treated borated water, treated water 

Reduction of neutronabsorbing capacity; change in dimensions and loss of material due to effects of SFP environment 

AMP XI.M40, "Monitoring of Neutron-Absorbing Materials other than Boraflex" 

No VII.A2.AP-235 

VII.A2.AP-236 

M 103 BWR/PWR Concrete, concrete 

cylinder piping, reinforced concrete, asbestos cement, cementitious piping, piping components exposed to soil, concrete 

Cracking due to chemical reaction, weathering, or corrosion of reinforcement (reinforced concrete only); loss of material due to delamination, exfoliation, spalling, popout, or scaling 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-157 

M 104 BWR/PWR HDPE, fiberglass 

piping, piping components exposed to soil, concrete 

Cracking, blistering, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-175 

VII.I.AP-176 

D 105 D 106 M 107 BWR/PWR Stainless steel, nickel 

alloy piping, piping components exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-137 
3.3-40 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 108 BWR/PWR Titanium, super 

austenitic, copper alloy, stainless steel, nickel alloy piping, piping components, tanks, closure bolting exposed to soil, concrete, underground 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC (super austenitic, copper alloy, stainless steel, nickel alloy; soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-171 

VII.I.AP-172 VII.I.AP-174 VII.I.AP-243 

M 109 BWR/PWR Steel piping, piping 

components, closure bolting exposed to soil, concrete, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-198 

VII.I.AP-241 VII.I.AP-284 

D 109a M 110 BWR Stainless steel, nickel 

alloy piping, piping components greater than or equal to 4 NPS exposed to treated water >93°C (>200°F) 

Cracking due to SCC, IGSCC 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

No VII.E4.A-61 

M 111 BWR/PWR Steel structural steel 

exposed to air – indoor uncontrolled 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No VII.A1.A-94 

M 112 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.3.2.2.9) 

VII.J.AP-282 

M 113 BWR/PWR Aluminum piping, 

piping components exposed to gas 

None None No 

VII.J.AP-37 

M 114 BWR/PWR Copper alloy piping, 

piping components exposed to air, condensation, gas 

None None No VII.J.AP-144 

VII.J.AP-9 
3.3-41 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 115 BWR/PWR Copper alloy, copper 

alloy (>8% Al) piping, piping components exposed to air with borated water leakage 

None None No VII.J.AP-11 

M 116 BWR/PWR Galvanized steel 

piping, piping components exposed to air – indoor uncontrolled 

None None No VII.J.AP-13 

M 117 BWR/PWR Glass piping elements 

exposed to air, lubricating oil, closedcycle cooling water, fuel oil, raw water, treated water, treated borated water, air with borated water leakage, condensation, gas, underground 

None None No VII.J.AP-14 

VII.J.AP-15 VII.J.AP-166 VII.J.AP-48 VII.J.AP-49 VII.J.AP-50 VII.J.AP-51 VII.J.AP-52 VII.J.AP-96 VII.J.AP-97 VII.J.AP-98 

D 118 M 119 BWR/PWR Nickel alloy, PVC, 

glass piping, piping components exposed to air with borated water leakage, air – indoor uncontrolled, condensation, waste water, raw water (potable) 

None None No VII.J.AP-260 

VII.J.AP-268 VII.J.AP-269 VII.J.AP-277 

M 120 BWR/PWR Stainless steel piping, 

piping components exposed to air with borated water leakage, gas 

None None No VII.J.AP-18 

VII.J.AP-22 
3.3-42 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 121 BWR/PWR Steel piping, piping 

components exposed to air – indoor controlled, gas 

None None No VII.J.AP-2 

VII.J.AP-6 

M 122 BWR/PWR Titanium heat 

exchanger components, piping, piping components exposed to air – indoor uncontrolled, air – outdoor 

None None No VII.J.AP-151 

VII.J.AP-160 

M 123 BWR/PWR Titanium heat 

exchanger components other than tubes, piping and piping components exposed to raw water 

Cracking due to SCC, flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.AP-152a

VII.C3.AP-152aVII.E4.AP-152aVII.H2.AP-152aVII.C1.AP-152bVII.C1.AP-161aVII.C3.AP-161aVII.E4.AP-161aVII.H2.AP-161aVII.C1.AP-161b 

M 124 BWR/PWR Stainless steel, steel 

(with stainless steel or nickel alloy cladding) spent fuel storage racks (BWR), spent fuel storage racks (PWR), piping, piping components exposed to treated water >60°C (>140°F), treated borated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, 

"Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A2.A-96 

VII.A2.A-97 VII.A3.A-56 VII.E1.A-103 
3.3-43 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 125 BWR/PWR Stainless steel, steel 

(with stainless steel cladding), nickel alloy spent fuel storage racks (BWR), spent fuel storage racks (PWR), piping, piping components exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A2.AP-79 

VII.A3.AP-79 VII.E1.AP-79 VII.A2.A-98 VII.A2.A-99 

M 126 BWR/PWR Metallic piping, piping 

components exposed to treated water, treated borated water, raw water 

Wall thinning due to erosion AMP XI.M17, 

"Flow-Accelerated Corrosion" 

No VII.C1.A-409 

VII.E1.A-407 VII.E3.A-408 

M 127 BWR/PWR Metallic piping, piping 

components, tanks exposed to closedcycle cooling water, raw water, raw water (potable), treated water, waste water 

Loss of material due to recurring internal corrosion 

AMP XI.M20, "Open-Cycle Cooling Water System," AMP XI.M27, "Fire Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.3.2.2.7) 

VII.C1.A-400 VII.C3.A-400 VII.E5.A-400 VII.G.A-400 

M 128 BWR/PWR Steel tanks (within the 

scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete, air, condensation, raw water 

Loss of material due to general, pitting, crevice corrosion, MIC (soil, raw water only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.C3.A-401 

VII.E5.A-401 VII.H1.A-401 

D 129 
3.3-44 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 130 BWR/PWR Metallic sprinklers 

exposed to air, condensation, raw water, raw water (potable), treated water 

Loss of material due to general (where applicable), pitting, crevice corrosion, MIC (except for aluminum, and in raw water, raw water (potable), treated water only); flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.A-403 

M 131 BWR/PWR Steel, stainless steel, 

copper alloy, aluminum piping, piping components exposed to air, condensation 

Flow blockage due to fouling AMP XI.M27, 

"Fire Water System" 

No VII.G.A-404 

M 132 BWR/PWR Insulated steel, 

copper alloy (>15% Zn or >8% Al), piping, piping components, tanks, tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to general, pitting, crevice corrosion (steel only); cracking due to SCC (copper alloy (>15% Zn or >8% Al) only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" or AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.I.A-405a 

VII.I.A-405b 

M 133 BWR/PWR HDPE underground 

piping, piping components 

Cracking, blistering AMP XI.M41, "Buried 

and Underground Piping and Tanks" 

No VII.I.A-406 

M 134 BWR/PWR Steel, stainless steel, 

copper alloy piping, piping components, and heat exchanger components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-727 
3.3-45 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 135 BWR/PWR Steel, stainless steel 

pump casings exposed to waste water environment 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.E5.A-410 

VII.E5.A-411 

M 136 BWR/PWR Steel fire water 

storage tanks exposed to air, condensation, soil, concrete, raw water, raw water (potable), treated water 

Loss of material due to general, pitting, crevice corrosion, MIC (raw water, raw water (potable), treated water, soil only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-412 

M 137 BWR/PWR Steel, stainless steel, 

aluminum tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to treated water, raw water, waste water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC (steel, stainless steel only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.C3.A-413 

VII.E5.A-413 VII.H1.A-413 

M 138 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, raw water (potable), treated water, treated borated water, fuel oil, lubricating oil, waste water 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage; loss of material or cracking for cementitious coatings/linings 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.C1.A-416 

VII.C2.A-416 VII.C3.A-416 VII.E4.A-416 VII.E5.A-416 VII.F1.A-416 VII.F2.A-416 VII.F3.A-416 VII.F4.A-416 VII.G.A-416 VII.H1.A-416 VII.H2.A-416 
3.3-46 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 139 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, raw water (potable), treated water, treated borated water, fuel oil, lubricating oil, waste water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.C1.A-414 

VII.C2.A-414 VII.C3.A-414 VII.E4.A-414 VII.E5.A-414 VII.F1.A-414 VII.F2.A-414 VII.F3.A-414 VII.F4.A-414 VII.G.A-414 VII.H1.A-414 VII.H2.A-414 

M 140 BWR/PWR Gray cast iron, ductile 

iron piping components with internal coatings/linings exposed to closedcycle cooling water, raw water, raw water (potable), treated water, waste water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.C1.A-415 

VII.C2.A-415 VII.C3.A-415 VII.E2.A-415 VII.E3.A-415 VII.E4.A-415 VII.E5.A-415 VII.G.A-415 VII.H1.A-415 VII.H2.A-415 

D 141 N 142 BWR/PWR Stainless steel, steel, 

nickel alloy, copper alloy closure bolting exposed to fuel oil, lubricating oil, treated water, treated borated water, raw water, waste water 

Loss of material due to general (steel; copper alloy in raw water, waste water only), pitting, crevice corrosion, MIC (raw water and waste water environments only) 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-423 

D 143 N 144 BWR/PWR Stainless steel, steel, 

aluminum piping, piping components, tanks exposed to soil, concrete 

Cracking due to SCC (steel in carbonate/bicarbonate environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.A-425 
3.3-47 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 145 BWR/PWR Stainless steel closure 

bolting exposed to air, soil, concrete, underground, waste water 

Cracking due to SCC AMP XI.M18, 

"Bolting Integrity" 

No VII.I.A-426 

N 146 BWR/PWR Stainless steel 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.I.A-714a VII.I.A-714b VII.I.A-714c 

N 147 BWR/PWR Nickel alloy, nickel 

alloy cladding piping, piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-471 

D 148 N 149 BWR/PWR Fiberglass piping, 

piping components, ducting, ducting components exposed to air – outdoor 

Cracking, blistering, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-428 

N 150 BWR/PWR Fiberglass piping, 

piping components, ducting, ducting components exposed to air 

Cracking, blistering, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-720 
3.3-48 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 151 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger tubes exposed to air, condensation 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-716 

D 153 D 154 N 155 BWR/PWR Stainless steel piping, 

piping components, and tanks exposed to waste water >60°C (>140°F) 

Cracking due to SCC AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.A-721 

D 156 N 157 BWR/PWR Steel piping, piping 

components, heat exchanger components exposed to air-outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M27, "Fire Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E1.A-722 

VII.E2.A-722 VII.E3.A-722 VII.E4.A-722 VII.E5.A-722 VII.F1.A-722 VII.F2.A-722 VII.F3.A-722 VII.F4.A-722 VII.G.A-722 VII.H1.A-722 VII.H2.A-722 

N 158 BWR/PWR Nickel alloy piping, 

piping components heat exchanger components (for components not covered by NRC GL 89-13) exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-454 
3.3-49 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 159 BWR/PWR Fiberglass piping, 

piping components, ducting, ducting components exposed to air 

Loss of material due to wear AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.D.A-495 

VII.E5.A-495 VII.F1.A-495 VII.F2.A-495 VII.F3.A-495 VII.F4.A-495 VII.G.A-495 VII.H1.A-495 VII.H2.A-495 

N 160 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components, heat exchanger components exposed to closed-cycle cooling water, raw water, waste water 

Cracking due to SCC AMP XI.M20, 

"Open-Cycle Cooling Water System," AMP XI.M21A, "Closed Treated Water Systems," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-473b 

VII.C2.A-473a VII.E5.A-473c 

N 161 BWR/PWR Copper alloy heat 

exchanger tubes exposed to condensation 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.A-565 

VII.F2.A-565 VII.F3.A-565 VII.F4.A-565 VII.G.A-565 VII.H2.A-565 

D 162 D 164 D 165 N 166 BWR/PWR Copper alloy piping, 

piping components exposed to concrete 

None None No VII.J.A-711 

N 167 BWR/PWR Zinc piping 

components exposed to air-indoor controlled, air – indoor uncontrolled 

None None No VII.J.A-712 
3.3-50 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 169 BWR/PWR Steel, copper alloy 

piping, piping components exposed to steam 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-566 

VII.F2.A-566 VII.F3.A-566 VII.F4.A-566 

N 170 BWR/PWR Stainless steel piping, 

piping components exposed to steam 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-567 

VII.F2.A-567 VII.F3.A-567 VII.F4.A-567 

D 171 N 172 BWR/PWR PVC piping, piping 

components exposed to air-outdoor 

Reduction in impact strength due to photolysis 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.C1.A-458 

VII.E5.A-458 VII.G.A-458 

D 173 D 174 N 175 BWR/PWR Fiberglass piping, 

piping components, tanks exposed to raw water (for components not covered by NRC GL 89-13), raw water (potable), treated water, waste water 

Cracking, blistering, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture; flow blockage due to fouling (raw water, waste water only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-460 

VII.E5.A-551 VII.G.A-644 

N 176 BWR/PWR Fiberglass piping, 

piping components, tanks exposed to raw water environment (for components not covered by NRC GL 89-13), raw water (potable), treated water, waste water 

Loss of material due to wear; flow blockage due to fouling (raw water, waste water only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-461 

VII.E5.A-552 VII.G.A-645 

N 177 BWR/PWR Fiberglass piping, 

piping components exposed to soil 

Loss of material due to wear AMP XI.M41, "Buried 

and Underground Piping and Tanks" 

No VII.I.A-462 
3.3-51 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 178 BWR/PWR Fiberglass piping and 

piping components exposed to concrete 

None None No VII.J.A-710 

N 179 BWR/PWR Masonry walls: 

structural fire barriers exposed to air 

Cracking due to restraint shrinkage, creep, aggressive environment; loss of material (spalling, scaling) and cracking due to freeze-thaw 

AMP XI.M26, "Fire Protection," and AMP XI.S5, "Masonry Walls" 

No VII.G.A-626 

D 180 N 181 BWR/PWR Titanium piping, piping 

components exposed to condensation 

None None No VII.J.A-703 

N 182 BWR/PWR Non-metallic thermal 

insulation exposed to air, condensation 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-704 

N 184 BWR/PWR PVC piping, piping 

components, tanks exposed to concrete 

None None No VII.J.A-709 

N 185 BWR/PWR Aluminum fire water 

storage tanks exposed to air, condensation, soil, concrete, raw water, raw water (potable), treated water 

Cracking due to SCC AMP XI.M27, 

"Fire Water System" 

No VII.G.A-623 
3.3-52 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 186 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation, soil, concrete, raw water, waste water 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.C3.A-482a VII.C3.A-482b VII.C3.A-482c VII.E5.A-482a VII.E5.A-482b VII.E5.A-482c VII.H1.A-482a VII.H1.A-482b VII.H1.A-482c 

D 187 N 189 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation, raw water, raw water (potable), waste water 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.A2.A-451a VII.A2.A-451b VII.A2.A-451c VII.A2.A-451d VII.A3.A-451a VII.A3.A-451b VII.A3.A-451c VII.A3.A-451d VII.A4.A-451a VII.A4.A-451b VII.A4.A-451c VII.A4.A-451d VII.C1.A-451a VII.C1.A-451b VII.C1.A-451c VII.C1.A-451d VII.C2.A-451a VII.C2.A-451b VII.C2.A-451c VII.C2.A-451d VII.C3.A-451a VII.C3.A-451b VII.C3.A-451c 
3.3-53 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

VII.C3.A-451d VII.D.A-451a VII.D.A-451b VII.D.A-451c VII.D.A-451d VII.E1.A-451a VII.E1.A-451b VII.E1.A-451c VII.E1.A-451d VII.E2.A-451a VII.E2.A-451b VII.E2.A-451c VII.E2.A-451d VII.E3.A-451a VII.E3.A-451b VII.E3.A-451c VII.E3.A-451d VII.E4.A-451a VII.E4.A-451b VII.E4.A-451c VII.E4.A-451d VII.E5.A-451a VII.E5.A-451b VII.E5.A-451c VII.E5.A-451d VII.F1.A-451a VII.F1.A-451b VII.F1.A-451c VII.F1.A-451d VII.F2.A-451a VII.F2.A-451b VII.F2.A-451c VII.F2.A-451d VII.F3.A-451a VII.F3.A-451b VII.F3.A-451c VII.F3.A-451d VII.F4.A-451a VII.F4.A-451b 
3.3-54 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

VII.F4.A-451c VII.F4.A-451d VII.G.A-451a VII.G.A-451b VII.G.A-451c VII.G.A-451d VII.H1.A-451a VII.H1.A-451b VII.H1.A-451c VII.H1.A-451d VII.H2.A-451a VII.H2.A-451b VII.H2.A-451c VII.H2.A-451d 

D 190 D 191 N 192 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.I.A-706a VII.I.A-706b VII.I.A-706c 
3.3-55 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 193 BWR/PWR Steel components 

exposed to treated water, raw water, raw water (potable), waste water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "One-Time Inspection" 

No VII.A3.A-439 

VII.A4.A-439 VII.C1.A-532 VII.C2.A-439 VII.C3.A-532 VII.E1.A-439 VII.E2.A-439 VII.E3.A-439 VII.E4.A-532 VII.E5.A-785 VII.G.A-439 VII.G.A-532 VII.H2.A-439 VII.H2.A-532 

N 194 BWR/PWR PVC piping, piping 

components, and tanks exposed to soil 

Loss of material due to wear AMP XI.M41, "Buried 

and Underground Piping and Tanks" 

No VII.I.A-537 

N 195 BWR/PWR Concrete, concrete 

cylinder piping, reinforced concrete, asbestos cement, cementitious piping, piping components exposed to raw water, treated water, raw water (potable) 

Cracking due to chemical reaction, weathering, settlement, or corrosion of reinforcement (reinforced concrete only); loss of material due to delamination, exfoliation, spalling, popout, scaling, or cavitation; flow blockage due to fouling (raw water only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-647 

N 196 BWR/PWR HDPE piping, piping 

components exposed to raw water, treated water, raw water (potable) 

Cracking, blistering; flow blockage due to fouling (raw water only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-648 
3.3-56 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 197 BWR/PWR Metallic fire water 

system piping, piping components, heat exchanger, heat exchanger components (any material) with only a leakage boundary (spatial) or structural integrity (attached) intended function exposed to any external environment except soil, concrete 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.G.A-649 

N 198 BWR/PWR Metallic fire water 

system piping, piping components, heat exchanger, heat exchanger components (any material) with only a leakage boundary (spatial) or structural integrity (attached) intended function 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion, MIC (all metallic materials except aluminum; in liquid environments only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.G.A-650 

N 199 BWR/PWR Cranes: steel 

structural bolting exposed to air 

Loss of preload due to selfloosening; loss of material due to general corrosion; cracking 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 

No VII.B.A-730 

D 200 N 202 BWR/PWR Stainless steel piping, 

piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.3.2.2.9) 

VII.J.AP-19 
3.3-57 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 203 BWR Stainless steel; steel 

with stainless steel cladding, nickel alloy piping, piping components, heat exchanger components, tanks exposed to treated water, sodium pentaborate solution 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One Time Inspection" 

No VII.A4.AP-110 

VII.A4.AP-111 VII.E2.AP-141 VII.E3.AP-110 VII.E4.AP-110 

D 204 N 205 BWR/PWR Insulated stainless 

steel piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.I.A-734a VII.I.A-734b VII.I.A-734c VII.I.A-734d 

D 206 N 207 BWR/PWR Stainless steel, copper 

alloy, titanium heat exchanger tubes exposed to raw water (for components not covered by NRC GL 89-13) 

Cracking due to SCC (titanium only), reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-736 
3.3-58 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 208 BWR/PWR Concrete, concrete 

cylinder piping, reinforced concrete, asbestos cement, cementitious piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Cracking due to chemical reaction, weathering, settlement, or corrosion of reinforcement (reinforced concrete only); loss of material due to delamination, exfoliation, spalling, popout, scaling, or cavitation; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-737 

D 209 N 210 BWR/PWR HDPE piping, piping 

components exposed to raw water (for components not covered by NRC GL 89-13) 

Cracking, blistering; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-739 

D 211 D 212 D 213 N 214 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components exposed to soil 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VII.C1.A-743 

VII.C2.A-743 VII.C3.A-743 VII.D.A-743 VII.E4.A-743 VII.E5.A-743 VII.G.A-743 VII.H1.A-743 VII.H2.A-743 

N 215 BWR/PWR Aluminum fire water 

storage tanks exposed to air, condensation, soil, concrete, raw water, raw water (potable), treated water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.A-744 
3.3-59 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 216 BWR/PWR Stainless steel fire 

water storage tanks exposed to air, condensation, soil, concrete 

Cracking due to SCC AMP XI.M27, "Fire 

Water System" 

No VII.G.A-745 

D 217 N 218 BWR/PWR Stainless steel fire 

water storage tanks exposed to air, condensation, soil, concrete, raw water, raw water (potable), treated water 

Loss of material due to pitting, crevice corrosion, MIC (water and soil environment only) 

AMP XI.M27, "Fire Water System" 

No VII.G.A-747 

N 219 BWR/PWR Stainless steel piping, 

piping components exposed to steam 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-748 

VII.F2.A-748 VII.F3.A-748 VII.F4.A-748 

D 220 D 221 
3.3-60 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 222 BWR/PWR Stainless steel, nickel 

alloy tanks exposed to air, condensation (internal/external) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.I.A-751b VII.I.A-751c VII.I.A-751d VII.I.A-751e 

N 223 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-752a VII.I.A-752b VII.I.A-752c 

D 224 D 225 
3.3-61 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 226 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.I.A-755 

N 227 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.C3.A-756a VII.C3.A-756b VII.C3.A-756c VII.E5.A-756a VII.E5.A-756b VII.E5.A-756c VII.H1.A-756a VII.H1.A-756b VII.H1.A-756c 

N 228 BWR/PWR Stainless steel, nickel 

alloy tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.C3.A-757a VII.C3.A-757b VII.C3.A-757c VII.E5.A-757a VII.E5.A-757b VII.E5.A-757c VII.H1.A-757a VII.H1.A-757b VII.H1.A-757c 
3.3-62 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 229 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.C3.A-758 

VII.E5.A-758 VII.H1.A-758 

N 230 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VII.C3.A-759 

VII.E5.A-759 VII.H1.A-759 

N 231 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.C3.A-760a VII.C3.A-760b VII.C3.A-760c VII.E5.A-760a VII.E5.A-760b VII.E5.A-760c VII.H1.A-760a VII.H1.A-760b VII.H1.A-760c 
3.3-63 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 232 BWR/PWR Insulated stainless 

steel, nickel alloy piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.I.A-761a VII.I.A-761b VII.I.A-761c VII.I.A-761d 

N 233 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.I.A-762a VII.I.A-762b VII.I.A-762c VII.I.A-762d 
3.3-64 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 234 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.A4.A-763a VII.A4.A-763b VII.A4.A-763c VII.A4.A-763d VII.C1.A-763a VII.C1.A-763b VII.C1.A-763c VII.C1.A-763d VII.C3.A-763a VII.C3.A-763b VII.C3.A-763c VII.C3.A-763d VII.E5.A-763a VII.E5.A-763b VII.E5.A-763c VII.E5.A-763d VII.F1.A-763a VII.F1.A-763b VII.F1.A-763c VII.F1.A-763d VII.F2.A-763a VII.F2.A-763b VII.F2.A-763c VII.F2.A-763d VII.F3.A-763a VII.F3.A-763b VII.F3.A-763c VII.F3.A-763d VII.F4.A-763a VII.F4.A-763b VII.F4.A-763c VII.F4.A-763d VII.H1.A-763a VII.H1.A-763b VII.H1.A-763c VII.H1.A-763d VII.H2.A-763a VII.H2.A-763b 
3.3-65 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

VII.H2.A-763c VII.H2.A-763d 

N 235 BWR/PWR Metallic piping, piping 

components exposed to air-dry (internal) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M24, "Compressed Air Monitoring" 

No VII.D.A-764 

N 236 BWR/PWR Titanium heat 

exchanger tubes exposed to treated water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A3.A-765 

VII.A4.A-765 VII.C1.A-765 VII.C3.A-765 VII.E1.A-765 VII.E3.A-765 VII.G.A-765 VII.H2.A-765 

N 237 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to treated water 

None None No VII.J.A-766 

N 238 BWR/PWR Titanium heat 

exchanger tubes exposed to closedcycle cooling water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-767 

VII.E3.A-767 VII.E4.A-767 VII.F1.A-767 VII.F2.A-767 VII.F3.A-767 VII.F4.A-767 

N 239 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to closedcycle cooling water 

None None No VII.J.A-768 
3.3-66 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 240 BWR/PWR Aluminum heat 

exchanger components exposed to waste water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.E5.A-769a VII.E5.A-769b VII.E5.A-769c VII.E5.A-769d 
3.3-67 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 241 BWR/PWR Stainless steel, nickel 

alloy heat exchanger components exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.F1.A-770a VII.F1.A-770b VII.F1.A-770c VII.F1.A-770d VII.F2.A-770a VII.F2.A-770b VII.F2.A-770c VII.F2.A-770d VII.F3.A-770a VII.F3.A-770b VII.F3.A-770c VII.F3.A-770d VII.F4.A-770a VII.F4.A-770b VII.F4.A-770c VII.F4.A-770d 
3.3-68 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 242 BWR/PWR Aluminum heat 

exchanger components exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.F1.A-771a VII.F1.A-771b VII.F1.A-771c VII.F1.A-771d VII.F2.A-771a VII.F2.A-771b VII.F2.A-771c VII.F2.A-771d VII.F3.A-771a VII.F3.A-771b VII.F3.A-771c VII.F3.A-771d VII.F4.A-771a VII.F4.A-771b VII.F4.A-771c VII.F4.A-771d 

D 243 N 244 BWR Stainless steel, nickel 

alloy piping, piping components exposed to treated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.A-773 

VII.E4.A-773 
3.3-69 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 245 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-774a VII.I.A-774b VII.I.A-774c VII.I.A-774d 

N 246 BWR/PWR Stainless steel, nickel 

alloy underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.I.A-775a VII.I.A-775b VII.I.A-775c 
3.3-70 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 247 BWR/PWR Aluminum piping, 

piping components, tanks exposed to raw water, waste water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.C1.A-776a VII.C1.A-776b VII.C1.A-776c VII.C1.A-776d VII.C3.A-776a VII.C3.A-776b VII.C3.A-776c VII.C3.A-776d VII.E5.A-776a VII.E5.A-776b VII.E5.A-776c VII.E5.A-776d 

N 248 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air with borated water leakage 

None None No VII.J.A-777 

N 249 BWR/PWR Steel heat exchanger 

tubes internal to components exposed to air-outdoor, airindoor uncontrolled, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-778 

VII.F1.A-778 VII.F2.A-778 VII.F3.A-778 VII.F4.A-778 

N 250 BWR/PWR Steel reactor coolant 

pump oil collection system tanks, piping, piping components exposed to lubricating oil (waste oil) 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M32, "One-Time Inspection" 

No VII.G.AP-116 

VII.G.AP-117 

D 251 
3.3-71 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 252 BWR/PWR Aluminum piping, 

piping components exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-173 

N 253 BWR/PWR PVC piping, piping 

components exposed to raw water, raw water (potable), treated water, waste water 

Loss of material due to wear; flow blockage due to fouling (raw water only) 

AMP XI.M20, "Open-Cycle Cooling Water System," AMP XI.M27, "Fire Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-787a 

VII.C1.A-787c VII.E5.A-787d VII.G.A-787b 

N 254 BWR/PWR Aluminum heat 

exchanger components exposed to air, condensation 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.F1.A-788a VII.F1.A-788b VII.F1.A-788c VII.F1.A-788d VII.F2.A-788a VII.F2.A-788b VII.F2.A-788c VII.F2.A-788d VII.F3.A-788a VII.F3.A-788b VII.F3.A-788c VII.F3.A-788d VII.F4.A-788a VII.F4.A-788b VII.F4.A-788c VII.F4.A-788d 
3.3-72 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 255 BWR/PWR Any material fire 

damper assemblies exposed to air 

Loss of material due to general, pitting, crevice corrosion; cracking due to SCC; hardening, loss of strength, shrinkage due to elastomer degradation 

AMP XI.M26, "Fire Protection" 

No VII.G.A-789 

D 256 N 257 BWR/PWR Steel, stainless steel, 

copper alloy heat exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "OneTime Inspection" 

No VII.C1.A-791 

VII.C2.A-791 VII.C3.A-791 VII.E1.A-791 VII.E4.A-791 VII.F1.A-791 VII.F2.A-791 VII.F3.A-791 VII.F4.A-791 VII.G.A-791 VII.H2.A-791 

N 258 BWR/PWR Metallic, elastomer, 

fiberglass, HDPE piping, piping components exposed to waste water 

Flow blockage due to fouling AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.A-780 
3.3-73 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 259 BWR/PWR Aluminum piping, 

piping components exposed to raw water 

Flow blockage due to fouling AMP XI.M20, 

"Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.A3.A-793 

VII.A4.A-793 VII.C1.A-793a VII.C1.A-793b VII.C2.A-793 VII.C3.A-793 VII.E1.A-793 VII.E2.A-793 VII.E3.A-793 VII.E4.A-793 VII.F1.A-793 VII.F2.A-793 VII.F3.A-793 VII.F4.A-793 VII.H1.A-793 VII.H2.A-793 

N 260 BWR/PWR Metallic HVAC closure 

bolting exposed to air, condensation 

Loss of material due to general (where applicable), pitting, crevice corrosion; cracking due to SCC, loss of preload 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.F1.A-794 

VII.F2.A-794 VII.F3.A-794 VII.F4.A-794 

N 261 BWR/PWR Titanium (ASTM 

Grades 3, 4, or 5) heat exchanger tubes exposed to closedcycle cooling water, raw water 

Cracking due to SCC AMP XI.M20, 

"Open-Cycle Cooling Water System," or AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C1.A-795a 

VII.C2.A-795b VII.C3.A-795a VII.E4.A-795a VII.H2.A-795a 
3.3-74 

Table 3.3-1 Summary of Aging Management Programs for Auxiliary Systems E

valuated in Chapter VII of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 262 BWR/PWR Titanium piping, piping 

components, heat exchanger components exposed to closed-cycle cooling water, treated water 

Cracking due to SCC AMP XI.M20, 

"Open-Cycle Cooling Water System," or AMP XI.M21A, "Closed Treated Water Systems," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-796a 

VII.C2.A-796b VII.C3.A-796a VII.E2.A-796c VII.E3.A-796c VII.E4.A-796a VII.H2.A-796a 

N 263 BWR/PWR Polymeric piping, 

piping components, ducting, ducting components, seals exposed to air, condensation, raw water, raw water (potable), treated water, waste water, underground, concrete, soil 

Hardening or loss of strength due to polymeric degradation; loss of material due to peeling, delamination, wear; cracking or blistering due to exposure to ultraviolet light, ozone, radiation, or chemical attack; flow blockage due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-797b 

VII.C2.A-797b VII.C3.A-797b VII.D.A-797b VII.E5.A-797b VII.F1.A-797b VII.F2.A-797b VII.F3.A-797b VII.F4.A-797b VII.G.A-797b VII.H1.A-797b VII.H2.A-797b VII.I.A-797a 
3.3-75 

Table 3.3-2 AMPs and Additional Guidance Appendices Recommended for 

Aging Management of Auxiliary Systems 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD 

AMP XI.M2 Water Chemistry 

AMP XI.M7 BWR Stress Corrosion Cracking 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M22 Boraflex Monitoring 

AMP XI.M23 Inspection of Overhead Heavy and Light Loads (Related to 

Refueling) Handling Systems 

AMP XI.M24 Compressed Air Monitoring 

AMP XI.M25 BWR Reactor Water Cleanup System 

AMP XI.M26 Fire Protection 

AMP XI.M27 Fire Water System 

AMP XI.M29 Outdoor and Large Atmospheric Metallic Storage Tanks 

AMP XI.M30 Fuel Oil Chemistry 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M40 Monitoring of Neutron-Absorbing Materials Other than 

Boraflex 

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

AMP XI.S6 Structures Monitoring 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 

3.4-1 

3.4 Aging Management of Steam and Power Conversion System 

Review Responsibilities 

Primary— The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.4.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management programs (AMPs) of the steam and power conversion system. For a recent vintage 

plant, the information related to the steam and power conversion system is contained in 

Chapter 10, “Steam and Power Conversion System,” of the plant’s Final Safety Analysis Report 

(FSAR), consistent with the “Standard Review Plan for the Review of Safety Analysis Reports for 

Nuclear Power Plants” (NUREG–0800). The steam and power conversion systems contained in 

this review plan section are generally consistent with those contained in NUREG–0800 except for 

the condenser circulating water and the condensate storage systems. For older plants, the 

location of applicable information is plant-specific because an older plant’s FSAR may have 

predated NUREG–0800. 

Typical steam and power conversion systems that are subject to an AMR for subsequent license 

renewal (SLR) are steam turbine, main steam, extraction steam, feedwater, condensate, steam 

generator blowdown, and auxiliary feedwater (AFW). This review plan section also includes 

structures and components (SCs) in nonsafety-related systems that are not connected to 

safety-related systems, structures, and components (SSCs) but have a spatial relationship such 

that their failure could adversely impact the performance of a safety-related SSC-intended 

function. Examples of such nonsafety-related systems may be extraction steam, plant heating 

steam/auxiliary boilers and hot water heating systems. 

The aging management for the steam generator is reviewed following the guidance in Section 3.1 

of this SRP-SLR. The aging management for portions of the boiling water reactor (BWR) main 

steam and main feedwater systems, extending from the reactor vessel to the outermost 

containment isolation valve, is reviewed separately following the guidance in Section 3.1 of 

this SRP-SLR. 

The responsible review organization is to review the following subsequent license renewal 

application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 1.2: 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 AMR results not consistent with or not addressed in the GALL-SLR Report 
3.4-2 

AMPs 

 Consistent with the GALL-SLR Report AMPs 

 Plant-specific AMPs; 

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.4.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

3.4.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The AMR and the AMPs applicable to the steam and power conversion system are described and 

evaluated in Chapter VIII of the GALL-SLR Report. 

The applicant’s SLRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

consistent with the GALL-SLR Report AMR item to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

capable of managing the effects of aging as adequately as the AMP recommended by the 

GALL-SLR Report. 

3.4.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria, defined in Subsection 3.4.2.1, need to be applied first for all of the 

AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR item 

to which the SLRA AMR item is compared identifies that “further evaluation is recommended,” 

then additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.4-1, comparing the “Further Evaluation 

Recommended” and the “GALL-SLR Item” column, for the AMR items that reference the 

following subsections. 

3.4.2.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be time-limited 

aging analyses (TLAAs), as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). This TLAA is addressed separately in SRP-SLR 

Section 4.3, “Metal Fatigue,” or Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses.” 

For plant-specific cumulative usage factor calculations that are based on stress-based input 

methods, the methods are to be appropriately defined and discussed in the applicable TLAAs. 
3.4-3 

3.4.2.2.2 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

Cracking due to stress corrosion cracking (SCC) could occur in indoor or outdoor stainless steel 

(SS) piping, piping components, and tanks exposed to any air, condensation, or underground 

environment when the component is: (a) uninsulated; (b) insulated; (c) in the vicinity of insulated 

components, or (d) in the vicinity of potentially transportable halogens. Cracking can occur in 

environments containing sufficient halides (e.g., chlorides) in the presence of moisture. 

Insulated SS components exposed to indoor air, outdoor air, condensation, or underground 

environments are susceptible to SCC if the insulation contains certain contaminants. Leakage of 

fluids through bolted connections (e.g., flanges, valve packing) can result in contaminants present 

in the insulation leaching onto the component surface or the surfaces of other components below 

the component. For outdoor insulated SS components, rain and changing weather conditions can 

result in moisture intrusion into the insulation. 

Plant-specific operating experience (OE) and the condition of SS components are evaluated to 

determine if prolonged exposure to the plant-specific environments has resulted in SCC. SCC in 

SS components is not an aging effect requiring management if (a) plant-specific OE does not 

reveal a history of SCC and (b) a one-time inspection demonstrates that the aging effect is 

not occurring. 

In the environment of air-indoor controlled, SCC is only expected to occur as the result of a source 

of moisture and halides. Inspections focus on the most susceptible locations. The applicant 

documents the results of the plant-specific OE review in the SLRA. 

The GALL-SLR Report recommends further evaluation of SS piping, piping components, and 

tanks exposed to an air, condensation, or underground environment to determine whether an 

AMP is needed to manage the aging effect of SCC. The GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” describes an acceptable program to demonstrate that SCC is not 

occurring. If SCC is occurring, the following AMPs describe acceptable programs to manage loss 

of material due to SCC: (a) GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric 

Metallic Storage Tanks,” for tanks; (b) GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” for external surfaces of piping and piping components; 

(c) GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground 

piping, piping components and tanks; and (d) GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” for internal surfaces of 

components that are not included in other AMPs. The timing of the one-time or periodic 

inspections is consistent with that recommended in the AMP selected by the applicant during the 

development of the SLRA. For example, one-time inspections would be conducted between the 

50th and 60th year of operation, as recommended by the “detection of aging effects” program 

element in AMP XI.M32. 

The applicant may establish that SCC is not an aging effect requiring management for all 

components, by demonstrating that a barrier coating isolates the component from aggressive 

environments. Acceptable barriers include tightly-adhering coatings that have been demonstrated 

to be impermeable to aqueous solutions and air that contain halides. The GALL-SLR Report AMP 

XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 

and Tanks,” describes an acceptable program to manage the integrity of a barrier coating. 
3.4-4 

3.4.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

Loss of material due to pitting and crevice corrosion could occur in indoor or outdoor SS and 

nickel alloy piping, piping components, and tanks exposed to any air, condensation, or 

underground environment when the component is: (a) uninsulated; (b) insulated; (c) in the vicinity 

of insulated components; or (d) in the vicinity of potentially transportable halogens. Loss of 

material due to pitting and crevice corrosion can occur on SS and nickel alloys in environments 

containing sufficient halides (e.g., chlorides) in the presence of moisture. 

Insulated SS and nickel alloy components exposed to air, condensation, or underground 

environments are susceptible to loss of material due to pitting or crevice corrosion if the insulation 

contains certain contaminants. Leakage of fluids through mechanical connections such as bolted 

flanges and valve packing can result in contaminants leaching onto the component surface or the 

surfaces of other components below the component. For outdoor insulated SS and nickel alloy 

components, rain, and changing weather conditions can result in moisture intrusion into 

the insulation. 

Plant-specific OE and the condition of SS and nickel alloy components are evaluated to determine 

if prolonged exposure to the plant-specific environments has resulted in pitting or crevice 

corrosion. Loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management for SS and nickel alloy components if (a) plant-specific OE does not reveal a history 

of loss of material due to pitting or crevice corrosion; and (b) a one-time inspection demonstrates 

that the aging effect is not occurring or is occurring so slowly that it will not affect the intended 

function of the components during the subsequent period of extended operation. The applicant 

documents the results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to 

occur as the result of a source of moisture and halides. Inspections focus on the most 

susceptible locations. 

The GALL-SLR Report recommends further evaluation of SS and nickel alloy piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that loss of material due to pitting and crevice corrosion is not 

occurring at a rate that affects the intended function of the components. If loss of material due to 

pitting or crevice corrosion has occurred and is sufficient to potentially affect the intended function 

of an SSC, the following AMPs describe acceptable programs to manage loss of material due to 

pitting or crevice corrosion: (a) GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric 

Metallic Storage Tanks,” for tanks; (b) GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” for external surfaces of piping and piping components; 

(c) GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground 

piping, piping components and tanks; and (d) GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” for internal surfaces of 

components that are not included in other AMPs. The timing of the one-time or periodic 

inspections is consistent with that recommended in the AMP selected by the applicant during the 

development of the SLRA. For example, one-time inspections would be conducted between the 

50th and 60th year of operation, as recommended by the “detection of aging effects” program 

element in AMP XI.M32. 
3.4-5 

The applicant may establish that loss of material due to pitting and crevice corrosion is not an 

aging effect requiring management by demonstrating that a barrier coating isolates the component 

from aggressive environments. Acceptable barriers include tightly-adhering coatings that have 

been demonstrated to be impermeable to aqueous solutions and air that contain halides. GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” describes an acceptable program to manage the integrity of a 

barrier coating. 

3.4.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in Branch Technical Position (BTP) IQMB-1 (Appendix A.2, of 

this SRP-SLR). 

3.4.2.2.5 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.4.2.2.6 Loss of Material Due to Recurring Internal Corrosion 

Recurring internal corrosion can result in the need to augment AMPs beyond the 

recommendations in the GALL-SLR Report. During the search of plant-specific OE conducted 

during the SLRA development, recurring internal corrosion can be identified by the number of 

occurrences of aging effects and the extent of degradation at each localized corrosion site. This 

further evaluation item is applicable if the search of plant specific OE reveals repetitive 

occurrences. The criteria for recurrence is (a) a 10 year search of plant specific OE reveals the 

aging effect has occurred in three or more refueling outage cycles; or (b) a 5 year search of plant 

specific OE reveals the aging effect has occurred in two or more refueling outage cycles and 

resulted in the component either not meeting plant specific acceptance criteria or experiencing a 

reduction in wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The GALL-SLR Report recommends that GALL-SLR Report AMP XI.M38, “Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components,” be evaluated for inclusion of 

augmented requirements to ensure the adequate management of any recurring aging effect(s). 

Alternatively, a plant-specific AMP may be proposed. Potential augmented requirements include: 

(i) alternative examination methods (e.g., volumetric versus external visual); (ii) augmented 

inspections (e.g., a greater number of locations, additional locations based on risk insights based 

on susceptibility to aging effect and consequences of failure, a greater frequency of inspections), 

and (iii) additional trending parameters and decision points where increased inspections would 

be implemented. 

The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

recurring aging effect before affecting the ability of a component to perform its intended function, 

(b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

parameters will be trended as well as the decision points where increased inspections would be 

implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

change), (d) how inspections of components that are not easily accessed (i.e., buried, 

underground) will be conducted, and (e) how leaks in any involved buried or underground 

components will be identified. 
3.4-6 

Plant-specific OE examples should be evaluated to determine if the chosen AMP should be 

augmented even if the thresholds for significance of aging effect or frequency of occurrence of 

aging effect have not been exceeded. For example, during a 10 year search of plant-specific OE, 

two instances of a 360 degree 30 percent wall loss occurred at copper alloy to steel joints. 

Neither the significance of the aging effect nor the frequency of occurrence of aging effect 

threshold has been exceeded. Nevertheless, the OE should be evaluated to determine if the 

AMP that is proposed to manage the aging effect is sufficient (e.g., method of inspection, 

frequency of inspection, number of inspections) to provide reasonable assurance that the current 

licensing basis (CLB) intended functions of the component will be met throughout the subsequent 

period of extended operation. While recurring internal corrosion is not as likely in other 

environments as raw water and waste water (e.g., treated water), the aging effect should be 

addressed in a similar manner. 

3.4.2.2.7 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

SCC is a form of environmentally assisted cracking which is known to occur in high and moderate 

strength aluminum alloys. The three conditions necessary for SCC to occur in a component are a 

sustained tensile stress, aggressive environment, and material with a susceptible microstructure. 

Cracking due to SCC can be mitigated by eliminating one of the three necessary conditions. For 

the purposes of SLR, acceptance criteria for this further evaluation is being provided for 

demonstrating that the specific material is not susceptible to SCC or an aggressive environment 

is not present. Cracking due to SCC is an aging effect requiring management unless it is 

demonstrated by the applicant that one of the two necessary conditions discussed below 

is absent. 

Susceptible Material: If the material is not susceptible to SCC, then cracking is not an aging effect 

requiring management. The microstructure of an aluminum alloy, of which alloy composition is 

only one factor, is what determines whether the alloy is susceptible to SCC. Therefore, 

determining susceptibility based on alloy composition alone is not adequate to conclude whether a 

particular material is susceptible to SCC. The temper, condition, and product form of the alloy is 

considered when assessing if a material is susceptible to SCC. Aluminum alloys that are 

susceptible to SCC include: 

 2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

 5xxx series alloys with a magnesium content of 3.5 weight percent or greater 

 6xxx series alloys in the F temper 

 7xxx series alloys in the F, T5x, or T6x temper 

 2xx.x and 7xx.x series alloys 

 3xx.x series alloys that contain copper 

 5xx.x series alloys with a magnesium content of greater than 8 weight percent 

The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

make the determination is technically substantiated. Tempers have been specifically developed 

to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 

combination which are not susceptible to SCC when used in piping, piping component, and tank 

applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. If it is determined that a 

material is not susceptible to SCC, the SLRA provides the components/locations where it is used, 

alloy composition, temper or condition, product form, and for tempers not addressed above, the 

basis used to determine the alloy is not susceptible and technical information substantiating 

the basis. 
3.4-7 

Aggressive Environment: If the environment to which an aluminum alloy is exposed is not 

aggressive, such as dry gas or treated water, then cracking due to SCC will not occur and it is not 

an aging effect requiring management. Aggressive environments that are known to result in 

cracking due to SCC of susceptible aluminum alloys are aqueous solutions, air, condensation, 

and underground locations that contain halides (e.g., chloride). Halide concentrations should be 

considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated aqueous 

solutions and air, such as raw water, waste water, condensation, underground locations, and 

outdoor air, unless demonstrated otherwise. 

Halides could be present on the surface of the aluminum material if the component is 

encapsulated in a material such as insulation or concrete. In a controlled or uncontrolled indoor 

air, condensation, or underground environment, sufficient halide concentrations to cause 

SCC could be present due to secondary sources such as leakage from nearby components 

(e.g., leakage from insulated flanged connections or valve packing). If an aluminum component is 

exposed to a halide-free indoor air environment, not encapsulated in materials containing halides, 

and the exposure to secondary sources of moisture or halides is precluded, cracking due to SCC 

is not expected to occur. The plant-specific configuration can be used to demonstrate that 

exposure to halides will not occur. If it is determined that SCC will not occur because the 

environment is not aggressive, the SLRA provides the components and locations exposed to the 

environment, description of the environment, basis used to determine the environment is not 

aggressive, and technical information substantiating the basis. GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” and a review of plant-specific OE describe an acceptable means to 

confirm the absence of moisture or halides within the proximity of the aluminum component. 

If the environment potentially contains halides, GALL-SLR Report AMP XI.M29, “Outdoor and 

Large Atmospheric Metallic Storage Tanks,” describes an acceptable program to manage 

cracking due to SCC of aluminum tanks. GALL-SLR Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” describes an acceptable program to manage cracking 

due to SCC of aluminum piping and piping components. GALL-SLR Report AMP XI.M41, “Buried 

and Underground Piping and Tanks,” describes an acceptable program to manage cracking due 

to SCC of aluminum piping and tanks which are buried or underground. GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components” 

describes an acceptable program to manage cracking due to SCC of aluminum components that 

are not included in other AMPs. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

barriers include tightly-adhering coatings that have been demonstrated to be impermeable to 

aqueous solutions and air that contain halides. GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” 

describes an acceptable program to manage the integrity of a barrier coating for internal or 

external coatings. 

3.4.2.2.8 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

Loss of material due to general (steel only), crevice, or pitting corrosion and cracking due to SCC 

(SS only) can occur in steel and SS piping and piping components exposed to concrete. 

Concrete provides a high alkalinity environment that can mitigate the effects of loss of material for 

steel piping, thereby significantly reducing the corrosion rate. However, if water intrudes through 

the concrete, the pH can be reduced and ions that promote loss of material such as chlorides, 
3.4-8 

which can penetrate the protective oxide layer created in the high alkalinity environment, can 

reach the surface of the metal. Carbonation can reduce the pH within concrete. The rate of 

carbonation is reduced by using concrete with a low water-to-cement ratio and low permeability. 

Concrete with low permeability also reduces the potential for the penetration of water. Adequate 

air entrainment improves the ability of the concrete to resist freezing and thawing cycles and 

therefore reduces the potential for cracking and intrusion of water. Cracking due to SCC, as well 

as pitting and crevice corrosion can occur due to halides present in the water that penetrates to 

the surface of the metal. 

If the following conditions are met, loss of material is not considered to be an applicable aging 

effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

(ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) 

as cited in NUREG–1557; (b) plant-specific OE indicates no degradation of the concrete that 

could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

exposed to groundwater. For SS components loss of material and cracking due to SCC are not 

considered to be applicable aging effects as long as the piping is not potentially exposed to 

groundwater. Where these conditions are not met, loss of material due to general (steel only), 

crevice, or pitting corrosion, and cracking due to SCC (SS only) are identified as applicable aging 

effects. GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes 

an acceptable program to manage these aging effects. 

3.4.2.2.9 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 

environment for a sufficient duration of time. Environments that can result in pitting and/or crevice 

corrosion of aluminum alloys are those that contain halides (e.g., chloride) in the presence of 

moisture. The moisture level and halide concentration in atmospheric and uncontrolled air are 

greatly dependent on geographical location and site-specific conditions. Moisture level and halide 

concentration should be considered high enough to facilitate pitting and/or crevice corrosion of 

aluminum alloys in atmospheric and uncontrolled air, unless demonstrated otherwise. The 

periodic introduction of moisture or halides into an environment from secondary sources should 

also be considered. Leakage of fluids from mechanical connections (e.g., insulated bolted flanges 

and valve packing); onto a component in indoor controlled air is an example of a secondary 

source that should be considered. Halide concentrations should be considered high enough to 

facilitate loss of material of aluminum alloys in untreated aqueous solutions, unless demonstrated 

otherwise. Plant-specific OE and the condition of aluminum alloy components are evaluated to 

determine if prolonged exposure to the plant-specific air, condensation, underground, or water 

environments has resulted in pitting or crevice corrosion. Loss of material due to pitting and 

crevice corrosion is not an aging effect requiring management for aluminum alloys if (a) plantspecific OE does not reveal a history of loss of material due to pitting or crevice corrosion and (b) 

a one-time inspection demonstrates that the aging effect is not occurring or is occurring so slowly 

that it will not affect the intended function of the components. The applicant documents the 

results of the plant-specific OE review in the SLRA. 

In the environment of air-indoor controlled, pitting and crevice corrosion is only expected to occur 

as the result of a source of moisture and halides. Alloy susceptibility may be considered when 

reviewing OE and interpreting inspection results. Inspections focus on the most susceptible alloys 

and locations. 
3.4-9 

The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

components, and tanks exposed to an air, condensation, or underground environment to 

determine whether an AMP is needed to manage the aging effect of loss of material due to pitting 

and crevice corrosion. GALL-SLR Report AMP XI.M32, “One-Time Inspection,” describes an 

acceptable program to demonstrate that the aging effect of loss of material due to pitting and 

crevice corrosion is not occurring at a rate that will affect the intended function of the components. 

If loss of material due to pitting or crevice corrosion has occurred and is sufficient to potentially 

affect the intended function of an SSC, the following AMPs describe acceptable programs to 

manage loss of material due to pitting and crevice corrosion: (i) GALL-SLR Report AMP XI.M29, 

“Outdoor and Large Atmospheric Metallic Storage Tanks,” for tanks; (ii) GALL-SLR Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” for external surfaces of 

piping and piping components; (iii) GALL-SLR Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” for underground piping, piping components and tanks; and (iv) GALL-SLR 

Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components” for internal surfaces of components that are not included in other AMPs. The timing 

of the one-time or periodic inspections is consistent with that recommended in the AMP selected 

by the applicant during the development of the SLRA. For example, one-time inspections would 

be conducted between the 50th and 60th year of operation, as recommended by the “detection of 

aging effects” program element in AMP XI.M32. 

An alternative strategy to demonstrating that an aggressive environment is not present is to 

isolate the aluminum alloy from the environment using a barrier to prevent loss of material due to 

pitting and crevice corrosion. Acceptable barriers include tightly-adhering coatings that have been 

demonstrated to be impermeable to aqueous solutions and air that contain halides. The GALLSLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” or equivalent program, describes an acceptable program to 

manage the integrity of a barrier coating. 

3.4.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.4.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and are based on the program elements 

of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs credited in the 

SLRA to confirm consistency with the GALL-SLR Report AMPs identified in Chapters X and XI. 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, the 

difference should be reviewed and properly dispositioned. The reviewer should document the 

disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP to 

be declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. 

The reviewer is to confirm both that the enhancement, when implemented, would allow the 
3.4-10 

existing SLRA AMP to be consistent with the GALL-SLR Report AMP and also that the applicant 

has a commitment in the FSAR Supplement to implement the enhancement prior to the 

subsequent period of extended operation. The reviewer should document the disposition of 

all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.4.2.5 Final Safety Analysis Report Supplement 

The summary description of the programs and activities for managing the effects of aging for the 

subsequent period of extended operation in the FSAR Supplement should be sufficiently 

comprehensive that later changes can be controlled by 10 CFR 50.59. The description should 

contain information associated with the bases for determining that aging effects will be managed 

during the subsequent period of extended operation. The description should also contain any 

future aging management activities, including enhancements and commitments, to be completed 

before the subsequent period of extended operation. Table X-01 and Table XI-01 of the 

GALL-SLR Report provide examples of the type of information to be included in the FSAR 

Supplement. Table 3.4-2 lists the programs that are applicable for this SRP-SLR subsection. 

3.4.3 Review Procedures 

For each area of review, the following review procedures discussed below are to be followed. 

3.4.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a re-review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to the GALL-SLR Report in its 

SLRA. In making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects have been addressed based on the NRC staff’s review of industry 

and plant-specific OE. 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review requires the reviewer to confirm 

that the applicant has identified those aging effects for the steam and power conversion system 

components that are contained in the GALL-SLR Report as applicable to its plant. 

3.4.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Subsection 3.4.3.1 need to be applied first for all of the 

AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to which 

the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply as identified by the GALL-SLR Report for each of the following aging 
3.4-11 

effect/aging mechanism combinations. Refer to Table 3.4-1 for the item references for the 

following subsections. 

3.4.3.2.1 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue or cyclical loading parameters may be TLAAs, 

as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c)(1). 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Section 4.3 or 4.7 (as applicable) to determine whether the applicant has provided 

a sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria in 

10 CFR 54.21(c)(1)(i), (ii), or (iii). This includes staff’s review of those cumulative usage 

factor analyses that qualify as TLAAs and are based on plant-specific, stress-based 

calculation methods. 

3.4.3.2.2 Cracking Due to Stress Corrosion Cracking in Stainless Steel Alloys 

The GALL-SLR Report recommends further evaluation to manage cracking due to SCC in SS 

piping, piping components, and tanks exposed to air and underground environments containing 

sufficient halides (e.g., chlorides) and in which condensation is possible. The possibility of 

cracking also extends to components exposed to air which has recently been introduced into 

buildings (i.e., components near intake vents) or where the component is in the vicinity of 

insulated components. 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals SCC in SS alloys, the reviewer determines whether 

an adequate program is credited to manage the aging effect. If the review of plant-specific OE 

reveals that SCC is not applicable, the reviewer verifies that the GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that SCC has 

occurred in the outdoor air environment but not the indoor air environment. The applicant could 

further categorize the indoor air locations as those where leakage could impinge on the SS 

component’s surface (e.g., leakage from mechanical connections) and those where there is not a 

potential for leakage. When the applicant chooses to conduct its OE search in this manner, the 

reviewer also is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include: leakage from mechanical connections; 

leakage into vaults; insulation containing halides; and outdoor air intrusion. Grouping of 

environments consistent with that described in the detection of aging effects program element of 

GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 
3.4-12 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

3.4.3.2.3 Loss of Material Due to Pitting and Crevice Corrosion in Stainless Steel and 

Nickel Alloys 

The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

and crevice corrosion of SS and nickel alloy piping and piping components exposed to any air, 

condensation, or underground environment, when the component is: (a) uninsulated; 

(b) insulated; (c) in the vicinity of insulated components where the presence of sufficient halides 

(e.g., chlorides) and moisture is possible; or (d) in the vicinity of potentially transportable halogens. 

The possibility of pitting and crevice corrosion also extends to indoor components located in close 

proximity to sources of outdoor air (e.g., components near intake vents). 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals loss of material due to pitting or crevice corrosion in 

SS and nickel alloys, the reviewer determines whether an adequate program is credited to 

manage the aging effect. If the review of plant-specific OE reveals that loss of material due to 

pitting and crevice corrosion is not applicable, the reviewer verifies that GALL-SLR Report 

AMP XI.M32, “One-Time Inspection,” is cited for all applicable AMR line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that loss of material 

due to pitting and crevice corrosion has occurred in the outdoor air environment but not the indoor 

air environment. The applicant could further categorize the indoor air locations as those where 

leakage could impinge on the SS or nickel alloy component’s surface (e.g., leakage from 

mechanical connections) and those where there is not a potential for leakage. When the applicant 

chooses to conduct its OE search in this manner, the reviewer is to also confirm that the applicant 

has adequately addressed the potential for the periodic introduction of either moisture or halides 

from secondary sources. Secondary sources of moisture or halides should be considered for all 

environments including indoor conditioned air. Typical secondary sources of moisture or halides 

include: leakage from mechanical connections; leakage into vaults; insulation containing halides; 

and outdoor air intrusion. Grouping of environments consistent with that described in the 

detection of aging effects program element of GALL-SLR Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” is appropriate. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

3.4.3.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMPs for SLR should contain the elements of corrective actions, the confirmation 

process, and administrative controls. Safety-related components are covered by 10 CFR Part 50, 

Appendix B, which is adequate to address these program elements. However, Appendix B does 

not apply to nonsafety-related components that are subject to an AMP for SLR. Nevertheless, the 

applicant has the option to expand the scope of its 10 CFR Part 50, Appendix B program to 
3.4-13 

include these components and address these program elements. If the applicant chooses this 

option, the reviewer confirms that the applicant has documented such a commitment in the FSAR 

Supplement. An example description is in Appendix A of the GALL-SLR Report. If the applicant 

chooses alternative means, the branch responsible for quality assurance (QA) should be 

requested to review the applicant’s proposal on a case-by-case basis. 

3.4.3.2.5 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to 

ensure that the AMPs are effective to manage the aging effects for which they are created. The 

AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined 

through the evaluation of OE that the effects of aging may not be adequately managed. 

Additional information is in Appendix A.4, “Operating Experience for Aging Management 

Programs” of this SRP-SLR. 

In addition, the reviewer confirms that the applicant has provided an appropriate summary 

description of these activities in the FSAR Supplement. The GALL-SLR Report provides 

examples of the type of information to be included in the FSAR Supplement. 

3.4.3.2.6 Loss of Material Due to Recurring Internal Corrosion 

The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

aging effects. The reviewer conducts an independent review of plant-specific OE to determine 

whether the plant is currently experiencing recurring internal corrosion. This further evaluation 

item is applicable if the search of plant-specific OE reveals repetitive occurrences. The criteria for 

recurrence is (a) a 10-year search of plant specific OE reveals the aging effect has occurred in 

three or more refueling outage cycles; or (b) a 5-year search of plant specific OE reveals the 

aging effect has occurred in two or more refueling outage cycles as a result of which the 

component either did not meet plant-specific acceptance criteria or experienced a reduction in 

wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

The reviewer should evaluate plant-specific OE examples to determine if the chosen AMP should 

be augmented. For example, during a 10-year search of plant-specific OE, two instances of a 

360 degree 30 percent wall loss occurred at copper alloy to steel joints. Neither the significance 

of the aging effect nor the frequency of occurrence of aging effect threshold has been exceeded. 

Nevertheless, the OE should be evaluated to determine if the AMP that is proposed to manage 

the aging effect is sufficient (e.g., method of inspection, frequency of inspection, number of 

inspections) to provide reasonable assurance that the CLB intended functions of the component 

will be met throughout the subsequent period of extended operation. 

The reviewer determines whether a proposed program is adequate to manage recurring internal 

corrosion by evaluating the proposed AMP against the criteria in SRP-SLR Section 3.4.2.2.6. 

3.4.3.2.7 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

The GALL-SLR Report recommends the further evaluation of aluminum components (i.e., piping, 

piping components, and tanks) exposed to air, condensation, underground, or aqueous solutions 

that contain halides to manage cracking due to SCC. The reviewer must first determine if 

cracking due to SCC is applicable and requires aging management. Cracking is to be considered 
3.4-14 

applicable unless it is demonstrated that one of the two acceptance criteria are met by 

demonstrating that an aggressive environment is not present or the specific material is not 

susceptible, as discussed in Section 3.4.2.2.7. Additionally, guidance is also provided on the 

review of the third condition necessary for SCC to occur, a sustained tensile stress. Each of three 

conditions is evaluated based on the review procedures below. 

If the material used to fabricate the component being evaluated is not susceptible to SCC then 

cracking due to SCC is not an aging effect requiring management. When determining if an 

aluminum alloy is susceptible to SCC the reviewer is to verify the materials: (a) alloy composition, 

(b) condition or temper, and (c) product form. Additionally, if the material was produced using a 

process specifically developed to provide a SCC resistant microstructure then the reviewer will 

consider the effects of this processing in the review. Once the material information has been 

established the reviewer is to evaluate the technical justification used to substantiate that the 

material is not susceptible to SCC when exposed to an aggressive environment and sustained 

tensile stress. The reviewer will evaluate all documentation and references used by the applicant 

as part of a technical justification. 

If the environment to which an aluminum alloy is exposed is not aggressive, such as dry gas, or 

treated water, then cracking due to SCC is not an aging effect requiring management. The 

environments cited in the AMR line items in the GALL-SLR Report that reference this further 

evaluation are considered to be aggressive and potentially containing halide concentrations that 

facilitate SCC of aluminum alloys. The reviewer is to verify that components are not also 

periodically exposed to nontypical environments that would be categorized as aggressive, such as 

secondary sources of moisture or halides, including outdoor air which has recently been 

introduced into a building and the leakage/seepage of untreated aqueous solutions into a building 

or underground vault. Controlled indoor air is not considered aggressive unless secondary 

sources of moisture or halides are present. When applicable, the staff reviews the basis for the 

applicant’s claim that the plant configuration precludes the potential presence of secondary 

sources of moisture or halides. Using information provided by the applicant, the reviewer will also 

evaluate the chemical composition of applicable encapsulating materials (e.g., concrete, 

insulation) for halides. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then cracking due to SCC is not an aging effect requiring management. The reviewer verifies that 

the barrier coating is impermeable to the applicable environments and verifies that loss of coating 

integrity is being managed for the associated components with a program equivalent to the 

GALL-SLR Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” 

If the sustained tensile stress being experienced by a component is below the SCC threshold 

value, then cracking is not an aging effect requiring management. Many aluminum alloys do not 

have a true SCC threshold stress, although a practical SCC threshold value can be determined 

based on the material, service environment, and duration of intended function. The basis for the 

SCC threshold value is to be evaluated to determine its applicability. The magnitude of the 

maximum tensile service stress (applied and residual) experienced by the component is to be 

evaluated to verify that the stress levels are bounded by the SCC threshold value. 

The information necessary to determine if SCC is applicable based on the sustained service 

stress is often not readily available. The SCC threshold stress level is dependent on both the 

alloy (e.g., chemical composition, processing history, and microstructure) and service 

environment. Furthermore, the magnitude and state of the residual stress sustained by a 
3.4-15 

component is typically not fully characterized. The reviewer must determine the adequacy of both 

the SCC threshold value being used by the applicant and the magnitude of the tensile stress 

being experienced by the component. The evaluation of the SCC threshold value includes the 

verification that the: (a) test method used to establish the threshold value is standardized and 

recognized by the industry, (b) data are statistically significant or conservative, and (c) data are for 

a relevant alloy, temper, product form, and environment. The evaluation of the tensile stress 

being experienced by the component includes the verification that the stress analysis accounts for 

(a) all applied and residual stresses and (b) stress riser that can initiate SCC cracks, such as 

corrosion pits and fabrication defects. 

Documentation that may assist the reviewer in determining if cracking due to SCC is applicable 

and requires aging management include: (a) component drawings, (b) applicable codes 

or specifications used in the design, fabrication, and installation of the component, 

(c) material-specific material certification data and lot release data, (d) maintenance records, 

and (e) plant-specific OE. 

If it is determined that cracking due to SCC is applicable, the reviewer is to evaluate the applicants 

proposed AMP to ensure that cracking is adequately managed so that the component’s intended 

functions will be maintained consistent with the CLB for the subsequent period of extended 

operation. The GALL-SLR Report AMP XI.M29, “Outdoor and Large Atmospheric Metallic 

Storage Tanks,” describes an acceptable program to manage cracking due to SCC of aluminum 

in tanks. The GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” describes an acceptable program to manage cracking due to SCC of aluminum 

piping and piping components. The GALL-SLR Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” describes an acceptable program to manage cracking due to SCC of 

aluminum piping and tanks which are buried or underground. The GALL-SLR Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components” 

describes an acceptable program to manage cracking due to SCC of aluminum components that 

are not included in other AMPs. 

3.4.3.2.8 Loss of Material Due to General, Crevice or Pitting Corrosion and Cracking Due to 

Stress Corrosion Cracking 

The GALL-SLR Report recommends that for steel piping and piping components exposed to 

concrete, if the following conditions are met, loss of material is not considered to be an applicable 

aging effect for steel: (a) 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; 

(b) plant-specific OE indicates no degradation of the concrete that could lead to penetration of 

water to the metal surface; and (c) the piping is not potentially exposed to groundwater. For SS 

piping and piping components, loss of material and cracking due to SCC are not considered to be 

applicable aging effects as long as the piping is not potentially exposed to groundwater. Where 

these conditions are not met, loss of material due to general (steel only), crevice or pitting 

corrosion and cracking due to SCC (SS only) are identified as applicable aging effects. 

GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and Tanks,” describes an 

acceptable program to manage these aging effects. 

The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-tocement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

reviewer should evaluate plant-specific OE to determine whether concrete degradation sufficient 

to allow water intrusion has occurred. 
3.4-16 

3.4.3.2.9 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

The GALL-SLR Report recommends a further evaluation to determine whether an AMP is needed 

to manage loss of material due to pitting and crevice corrosion of aluminum piping, piping 

components, and tanks exposed to an air, condensation, underground, raw water, or waste water 

environment. The reviewer is to conduct an independent assessment of plant-specific OE during 

the AMP audit to confirm that the applicant’s evaluation of its OE is adequate. 

The reviewer is to confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include: leakage from mechanical connections; 

leakage into vaults; insulation containing halides; and outdoor air intrusion. Grouping of 

environments consistent with that found in the GALL-SLR Report Section IX.D is appropriate. 

The grouping of OE search results based on environmental factors or plant configuration may be 

appropriate. The reviewer is to verify that the considerations given to groupings based on 

environmental factors and/or plant configuration have a substantiated technical basis. 

Components in the vicinity of secondary sources of moisture or halides may be treated as a 

separate population when performing inspections and interpreting results due to plant-specific 

configurations. 

The grouping of alloys based on relative susceptibility to loss of material may also be appropriate. 

The reviewer is to verify that the considerations given to alloy susceptibility and/or grouping have 

a substantiated technical basis. The high strength heat treatable aluminum alloys (2xxx and 7xxx 

series) may be treated as a separate population when performing inspections and interpreting 

results due to their relatively lower corrosion resistance. The relative susceptibility of moderate 

and lower strength alloys varies based on composition (primarily weight percent Cu, Mg, and Fe) 

and temper designation. 

The reviewer is to determine whether an adequate program is credited to manage the aging effect 

if the OE reveals that loss of material is applicable or the applicant elects to manage loss of 

material due to pitting or crevice corrosion. The reviewer is to verify that the SLRA cites the use of 

GALL-SLR Report AMP XI.M32, “One-Time Inspection,” for all aluminum piping, piping 

components, and tanks exposed to air, condensation, or underground environments when 

confirming that the aging effect is not applicable based on the OE evaluation. 

If components are effectively isolated from an aggressive environment by using a barrier coating, 

then loss of material due to pitting and crevice corrosion is not an aging effect requiring 

management. The reviewer verifies that the barrier coating is impermeable to the applicable 

environments and verifies that loss of coating integrity is being managed for the associated 

components with a program equivalent to the GALL-SLR Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

3.4.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging effects, 

listed the appropriate combination of materials and environments, and has credited AMPs that will 

adequately manage the aging effects. The AMP credited by the applicant could be an AMP that is 
3.4-17 

described and evaluated in the GALL-SLR Report or a plant-specific program. Review 

procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.4.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the steam and power conversion system are summarized in Table 3.4-1 of this 

SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR 

Report, Chapter VIII, presenting detailed information summarized by this row. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.4.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in the FSAR Supplement information for 

aging management of the steam and power conversion systems. Table 3.4-2 lists the AMPs that 

are applicable for this SRP-SLR subsection. The reviewer also confirms that the applicant has 

provided information for Subsection 3.4.3.3, “Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons Learned for Subsequent License 

Renewal Report.” 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 
3.4-18 

3.4.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has demonstrated that the aging effects associated with the steam and 

power conversion system components will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the subsequent 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

The NRC staff also reviewed the applicable FSAR Supplement program 

summaries and concludes that they adequately describe the AMPs credited for 

managing aging of the steam and power conversion system, as required by 

10 CFR 54.21(d). 

3.4.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.4.6 References 

1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML070630046. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 2007. 

2. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. ADAMS Accession No. 

ML051860406. Washington, DC: Nuclear Energy Institute. June 2005. 

3. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License Renewal.” 

Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 

4. ACI. ACI Standard 318-95, “Building Code Requirements for Reinforced Concrete and 

Commentary.” Farmington Hills, Michigan: American Concrete Institute. 1995. 

5. ACI. ACI Standard 349-85, “Code Requirements for Nuclear Safety-Related Concrete 

Structures.” Farmington Hills, Michigan: American Concrete Institute. 1985. 

6. ANSI. ANSI Standard H35.1/H35.1M, “Alloy and Temper Designation Systems for 

Aluminum.” New York, New York: American National Standards Institute, Inc. 2013. 

7. ASM. Corrosion of Aluminum and Aluminum Alloys. J. R. Davis, ed. Materials Park, 

Ohio: ASM International. 1999. 
3.4-19 

8. NRL. Stress-Corrosion Cracking in High Strength Steels and in Titanium and Aluminum 

Alloys. B. F. Brown, ed. Washington, DC: Naval Research Laboratory. 1972. 
3.4-20 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 001 BWR/PWR Steel piping, piping 

components exposed to any environment 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.4.2.2.1) 

VIII.B1.S-08 VIII.B2.S-08 VIII.D1.S-11 VIII.D2.S-11 VIII.G.S-11 

M 002 BWR/PWR Stainless steel 

piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.A.SP-118a VIII.A.SP-118b VIII.A.SP-118c VIII.A.SP-118d VIII.B1.SP-118aVIII.B1.SP-118bVIII.B1.SP-118c VIII.B1.SP-118dVIII.B2.SP-118aVIII.B2.SP-118bVIII.B2.SP-118c VIII.B2.SP-118dVIII.C.SP-118a VIII.C.SP-118b VIII.C.SP-118c VIII.C.SP-118d VIII.D1.SP-118aVIII.D1.SP-118bVIII.D1.SP-118cVIII.D1.SP-118dVIII.D2.SP-118aVIII.D2.SP-118bVIII.D2.SP-118cVIII.D2.SP-118dVIII.E.SP-118a VIII.E.SP-118b VIII.E.SP-118c VIII.E.SP-118d VIII.F.SP-118a VIII.F.SP-118b VIII.F.SP-118c VIII.F.SP-118d 
3.4-21 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

VIII.G.SP-118a VIII.G.SP-118b VIII.G.SP-118c VIII.G.SP-118d 

M 003 BWR/PWR Stainless steel, 

nickel alloy piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.A.SP-127a VIII.A.SP-127b VIII.A.SP-127c VIII.A.SP-127d VIII.B1.SP-127aVIII.B1.SP-127bVIII.B1.SP-127c VIII.B1.SP-127dVIII.B2.SP-127aVIII.B2.SP-127bVIII.B2.SP-127c VIII.B2.SP-127dVIII.C.SP-127a VIII.C.SP-127b VIII.C.SP-127c VIII.C.SP-127d VIII.D1.SP-127aVIII.D1.SP-127bVIII.D1.SP-127cVIII.D1.SP-127dVIII.D2.SP-127aVIII.D2.SP-127bVIII.D2.SP-127cVIII.D2.SP-127dVIII.E.SP-127a VIII.E.SP-127b VIII.E.SP-127c VIII.E.SP-127d VIII.F.SP-127a VIII.F.SP-127b VIII.F.SP-127c VIII.F.SP-127d VIII.G.SP-127a 
3.4-22 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

VIII.G.SP-127b VIII.G.SP-127c VIII.G.SP-127d 

M 004 PWR Steel external 

surfaces exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No VIII.H.S-30 

M 005 BWR/PWR Steel piping, piping 

components exposed to steam, treated water 

Wall thinning due to flowaccelerated corrosion AMP XI.M17, "Flow-Accelerated 

Corrosion" 

No VIII.A.S-15 

VIII.B1.S-15 VIII.B2.S-15 VIII.C.S-15 VIII.D1.S-16 VIII.D2.S-16 VIII.E.S-16 VIII.F.S-16 VIII.G.S-16 

M 006 BWR/PWR Metallic closure 

bolting exposed to any environment, soil, underground 

Loss of preload due to thermal effects, gasket creep, self-loosening 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.SP-142 

M 007 BWR/PWR High-strength steel 

closure bolting exposed to air, soil, underground 

Cracking due to SCC; cyclic loading 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-03 

D 008 M 009 BWR/PWR Steel, stainless 

steel, nickel alloy closure bolting exposed to airindoor uncontrolled, air-outdoor, condensation 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-02 

D 010 
3.4-23 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 011 BWR/PWR Stainless steel 

piping, piping components, tanks, heat exchanger components exposed to steam, treated water >60°C (>140°F) 

Cracking due to SCC AMP XI.M2, "Water 

Chemistry," and AMP-XI.M32, "One-Time Inspection" 

No VIII.A.SP-98 

VIII.B1.SP-88 VIII.B1.SP-98 VIII.B2.SP-98 VIII.C.SP-88 VIII.D1.SP-88 VIII.E.SP-88 VIII.E.SP-97 VIII.F.SP-85 VIII.F.SP-88 VIII.G.SP-88 

M 012 BWR/PWR Steel tanks exposed 

to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-75 

VIII.G.SP-75 

D 013 M 014 BWR/PWR Steel piping, piping 

components exposed to steam, treated water 

Loss of material due to general, pitting, crevice corrosion, MIC (treated water only) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One Time Inspection" 

No VIII.A.SP-71 

VIII.B1.SP-71 VIII.B1.SP-74 VIII.B2.SP-160 VIII.B2.SP-73 VIII.C.SP-71 VIII.C.SP-73 VIII.D1.SP-74 VIII.D2.SP-73 VIII.E.SP-73 VIII.F.SP-74 VIII.G.SP-74 

M 015 BWR/PWR Steel heat 

exchanger components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-77 
3.4-24 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 016 BWR/PWR Copper alloy, 

aluminum piping, piping components exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion, MIC (copper alloy only) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-101 

VIII.D1.SP-90 VIII.D2.SP-90 VIII.E.SP-90 VIII.F.SP-101 VIII.F.SP-90 VIII.G.SP-90 

D 017 M 018 BWR/PWR Copper alloy, 

stainless steel heat exchanger tubes exposed to treated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-100 

VIII.E.SP-96 VIII.F.SP-96 VIII.F.SP-100 VIII.G.SP-100 

M 019 BWR/PWR Stainless steel, 

steel heat exchanger components exposed to raw water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VIII.E.SP-117 

VIII.E.SP-146 VIII.F.SP-146 VIII.F.SP-117 VIII.G.SP-117 VIII.G.SP-146 

M 020 BWR/PWR Copper alloy, 

stainless steel piping, piping components exposed to raw water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VIII.A.SP-31 

VIII.E.SP-31 VIII.E.SP-36 VIII.F.SP-31 VIII.F.SP-36 VIII.G.SP-31 VIII.G.SP-36 

D 021 M 022 BWR/PWR Stainless steel, 

copper alloy, steel heat exchanger tubes exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VIII.E.S-28 

VIII.E.SP-56 VIII.F.S-28 VIII.G.S-27 VIII.G.S-28 VIII.G.SP-56 
3.4-25 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 023 BWR/PWR Stainless steel 

piping, piping components exposed to closedcycle cooling water >60°C (>140°F) 

Cracking due to SCC AMP XI.M21A, 

"Closed Treated Water Systems" 

No VIII.E.SP-54 

VIII.F.SP-54 VIII.G.SP-54 

D 024 M 025 BWR/PWR Steel heat 

exchanger components exposed to closedcycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.A.S-23 

VIII.E.S-23 VIII.F.S-23 VIII.G.S-23 

M 026 BWR/PWR Stainless steel heat 

exchanger components, piping, piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.E.S-25 

VIII.E.SP-39 VIII.F.S-25 VIII.F.SP-39 VIII.G.S-25 VIII.G.SP-39 

M 027 BWR/PWR Copper alloy piping, 

piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.E.SP-8 

VIII.F.SP-8 VIII.G.SP-8 

M 028 BWR/PWR Steel, stainless 

steel, copper alloy heat exchanger tubes exposed to closed-cycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.A.SP-64 

VIII.E.SP-41 VIII.E.SP-57 VIII.E.SP-64 VIII.F.SP-41 VIII.F.SP-64 VIII.G.SP-41 VIII.G.SP-64 

D 029 
3.4-26 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 030 BWR/PWR Steel tanks (within 

the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete, air, condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.E.SP-115 

VIII.G.SP-116 

D 031 M 032 BWR/PWR Gray cast iron, 

ductile iron piping, piping components exposed to soil 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.E.SP-26 

VIII.G.SP-26 

M 033 BWR/PWR Gray cast iron, 

ductile iron, copper alloy (>15% Zn or >8% Al) piping, piping components exposed to treated water, raw water, closed-cycle cooling water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.A.SP-27 

VIII.A.SP-28 VIII.A.SP-30 VIII.E.SP-27 VIII.E.SP-29 VIII.E.SP-30 VIII.E.SP-55 VIII.F.SP-27 VIII.F.SP-29 VIII.F.SP-30 VIII.F.SP-55 VIII.G.SP-27 VIII.G.SP-28 VIII.G.SP-29 VIII.G.SP-30 VIII.G.SP-55 

M 034 BWR/PWR Steel external 

surfaces exposed to air – indoor uncontrolled, air – outdoor, condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-29 
3.4-27 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 035 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.E.SP-147a VIII.E.SP-147b VIII.E.SP-147c VIII.E.SP-147d VIII.G.SP-147a VIII.G.SP-147b VIII.G.SP-147c VIII.G.SP-147d 

M 036 BWR/PWR Steel piping, piping 

components exposed to air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.B1.SP-59 

VIII.E.SP-59 VIII.G.SP-59 

M 037 BWR/PWR Steel piping, piping 

components exposed to condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.SP-60 

VIII.G.SP-60 

M 038 PWR Steel piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VIII.G.SP-136 

D 039 M 040 BWR/PWR Steel piping, piping 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-91 

VIII.D1.SP-91 VIII.D2.SP-91 VIII.E.SP-91 VIII.G.SP-91 
3.4-28 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

 041 PWR Steel heat 

exchanger components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-76 

M 042 PWR Aluminum piping, 

piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-114 

M 043 BWR/PWR Copper alloy piping, 

piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-92 

VIII.D1.SP-92 VIII.D2.SP-92 VIII.E.SP-92 VIII.G.SP-92 

M 044 BWR/PWR Stainless steel 

piping, piping components, heat exchanger components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-95 

VIII.D1.SP-95 VIII.D2.SP-95 VIII.E.SP-95 VIII.G.SP-79 VIII.G.SP-95 

M 045 BWR/PWR Aluminum heat 

exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-113 

VIII.G.SP-113 

 046 PWR Stainless steel, 

steel, copper alloy heat exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-102 

VIII.G.SP-103 VIII.G.SP-99 
3.4-29 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 047 BWR/PWR Stainless steel 

piping, piping components, tanks, closure bolting exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-145 

M 048 BWR/PWR Nickel alloy piping, 

piping components, tanks, closure bolting exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-143 

D 049 M 050 BWR/PWR Steel piping, piping 

components, tanks, closure bolting exposed to soil, concrete, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-141 

VIII.H.SP-161 

D 050a M 051 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.4.2.2.8) 

VIII.I.SP-154 

M 052 BWR/PWR Aluminum piping, 

piping components exposed to gas 

None None No VIII.I.SP-23 

M 053 BWR/PWR Copper alloy, 

copper alloy (>8% Al) piping, piping components exposed to air with borated water leakage 

None None No VIII.I.SP-104 

M 054 BWR/PWR Copper alloy piping, 

piping components exposed to air, condensation, gas 

None None No VIII.I.SP-6 
3.4-30 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 055 BWR/PWR Glass piping 

elements exposed to lubricating oil, air, condensation, raw water, treated water, air with borated water leakage, gas, closed-cycle cooling water 

None None No VIII.I.SP-10 

VIII.I.SP-33 VIII.I.SP-34 VIII.I.SP-35 VIII.I.SP-67 VIII.I.SP-68 VIII.I.SP-69 VIII.I.SP-70 

M 056 BWR/PWR Nickel alloy piping, 

piping components exposed to air with borated water leakage 

None None No VIII.I.SP-148 

M 057 BWR/PWR PVC piping, piping 

components exposed to air – indoor uncontrolled, condensation 

None None No VIII.I.SP-152 

VIII.I.SP-153 

M 058 BWR/PWR Stainless steel 

piping, piping components exposed to gas 

None None No VIII.I.SP-15 

M 059 BWR/PWR Steel piping, piping 

components exposed to air – indoor controlled, gas 

None None No VIII.I.SP-1 

VIII.I.SP-4 

M 060 BWR/PWR Metallic piping, 

piping components exposed to steam, treated water 

Wall thinning due to erosion AMP XI.M17, 

"Flow-Accelerated Corrosion" 

No VIII.A.S-408 

VIII.B1.S-408 VIII.B2.S-408 VIII.C.S-408 VIII.D1.S-408 VIII.D2.S-408 VIII.G.S-408 
3.4-31 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

M 061 BWR/PWR Metallic piping, 

piping components, tanks exposed to raw water, waste water 

Loss of material due to recurring internal corrosion 

AMP XI.M20, "Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.4.2.2.6) 

VIII.A.S-400a VIII.A.S-400b VIII.D1.S-400b VIII.D2.S-400b VIII.E.S-400a VIII.E.S-400b VIII.F.S-400a VIII.F.S-400b VIII.G.S-400a VIII.G.S-400b 

M 062 BWR/PWR Steel, stainless 

steel or aluminum tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to treated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC (steel, stainless steel only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.E.S-405 

VIII.G.S-405 

M 063 BWR/PWR Insulated steel, 

copper alloy (>15% Zn or >8% Al), piping, piping components, tanks, tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to general, pitting, crevice corrosion (steel only); cracking due to SCC (copper alloy (>15% Zn or >8% Al) only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" or AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.H.S-402a 

VIII.H.S-402b 

M 064 BWR/PWR Non-metallic 

thermal insulation exposed to air, condensation 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-403 
3.4-32 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

D 065 M 066 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, lubricating oil 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage; loss of material or cracking for cementitious coatings/linings 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.E.S-401 

VIII.F.S-401 VIII.G.S-401 

M 067 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.E.S-414 

VIII.F.S-414 VIII.G.S-414 

M 068 BWR/PWR Gray cast iron, 

ductile iron piping, piping components with internal coatings/linings exposed to closedcycle cooling water, raw water, treated water, waste water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.E.S-415 

VIII.F.S-415 VIII.G.S-415 

D 069 
3.4-33 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 070 BWR/PWR Stainless steel, 

steel, nickel alloy, copper alloy closure bolting exposed to lubricating oil, treated water, treated borated water, raw water, waste water 

Loss of material due to general (steel; copper alloy in raw water, waste water only), pitting, crevice corrosion, MIC (raw water, waste water environments only) 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-418 

D 071 N 072 BWR/PWR Stainless steel, 

steel, aluminum piping, piping components, tanks exposed to soil, concrete 

Cracking due to SCC (steel in carbonate/bicarbonate environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.S-420 

N 073 BWR/PWR Stainless steel 

closure bolting exposed to air, soil, concrete, underground, waste water 

Cracking due to SCC AMP XI.M18, 

"Bolting Integrity" 

No VIII.H.S-421 

N 074 BWR/PWR Stainless steel 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for InScope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.H.S-425a VIII.H.S-425b VIII.H.S-425c 
3.4-34 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 075 BWR/PWR Stainless steel, 

steel, aluminum, copper alloy, titanium heat exchanger tubes exposed to air, condensation 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-426 

N 077 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, condensation 

Hardening or loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-428 

N 078 BWR/PWR Elastomer piping, 

piping components, seals exposed to air, condensation 

Hardening or loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.D1.S-429 

VIII.D2.S-429 VIII.E.S-429 VIII.G.S-429 

D 080 N 081 BWR/PWR Steel components 

exposed to treated water, raw water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "One-Time Inspection" 

No VIII.A.S-432 

VIII.D1.S-432 VIII.D2.S-432 VIII.E.S-432 VIII.F.S-432 VIII.G.S-432 

N 082 BWR/PWR Stainless steel 

piping, piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.4.2.2.8) 

VIII.I.SP-13 

N 083 BWR/PWR Stainless steel, 

nickel alloy tanks exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-162 

VIII.G.SP-162 

N 084 BWR/PWR Stainless steel, 

nickel alloy piping, piping components exposed to steam 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-155 

VIII.B1.SP-155 VIII.B2.SP-155 VIII.B1.SP-157 
3.4-35 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 085 BWR/PWR Stainless steel, 

nickel alloy piping, piping components, PWR heat exchanger components exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.B1.SP-87 

VIII.C.SP-87 VIII.D1.SP-87 VIII.D2.SP-87 VIII.E.SP-80 VIII.E.SP-87 VIII.F.SP-80 VIII.F.SP-87 VIII.G.SP-87 

N 086 BWR/PWR Stainless steel, 

steel, aluminum, copper alloy, titanium heat exchanger tubes internal to components exposed to air, condensation 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-433 

VIII.G.S-433 

D 088 N 089 BWR/PWR Steel, stainless 

steel, copper alloy piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.A.S-436 

VIII.E.S-436 VIII.F.S-436 VIII.G.S-436 

N 090 BWR/PWR Steel, stainless 

steel, copper alloy heat exchanger tubes exposed to raw water (for components not covered by NRC GL 89-13) 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-437 

VIII.F.S-437 VIII.G.S-437 
3.4-36 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 091 BWR/PWR Steel, stainless 

steel, copper alloy heat exchanger components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-438 

VIII.F.S-438 VIII.G.S-438 

N 092 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components exposed to soil 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.D1.S-439 

VIII.D2.S-439 VIII.E.S-439 VIII.F.S-439 VIII.G.S-439 

D 093 N 094 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for InScope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.H.S-442a VIII.H.S-442b VIII.H.S-442c 

N 095 BWR/PWR Stainless steel, 

nickel alloy underground piping, piping components, tanks 

Loss of material due to pitting, crevice corrosion 

AMP XI.M32, "One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.H.S-443a VIII.H.S-443b VIII.H.S-443c 
3.4-37 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 096 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.E.S-444 

VIII.G.S-444 

N 097 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.E.S-445a VIII.E.S-445b VIII.E.S-445c VIII.G.S-445a VIII.G.S-445b VIII.G.S-445c 

N 098 BWR/PWR Stainless steel, 

nickel alloy tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.E.S-446a VIII.E.S-446b VIII.E.S-446c VIII.G.S-446a VIII.G.S-446b VIII.G.S-446c 
3.4-38 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 099 BWR/PWR Stainless steel 

tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil only) 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.E.S-447 

VIII.G.S-447 

N 100 BWR/PWR Stainless steel 

tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for InScope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.E.S-448a VIII.E.S-448b VIII.E.S-448c VIII.G.S-448a VIII.G.S-448b VIII.G.S-448c 

N 101 BWR/PWR Stainless steel 

tanks (within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to soil, concrete 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks" 

No VIII.E.S-449 

VIII.G.S-449 
3.4-39 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 102 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks") exposed to air, condensation, soil, concrete, raw water, waste water 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.E.S-450a VIII.E.S-450b VIII.E.S-450c VIII.G.S-450a VIII.G.S-450b VIII.G.S-450c 

N 103 BWR/PWR Insulated stainless 

steel, nickel alloy piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.H.S-451a VIII.H.S-451b VIII.H.S-451c VIII.H.S-451d 
3.4-40 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 104 BWR/PWR Insulated stainless 

steel piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.H.S-452a VIII.H.S-452b VIII.H.S-452c VIII.H.S-452d 

N 105 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M29, 

"Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.H.S-453a VIII.H.S-453b VIII.H.S-453c VIII.H.S-453d 
3.4-41 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 106 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components exposed to air, condensation 

Cracking due to SCC AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-454 

N 107 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) tanks exposed to air, condensation 

Cracking due to SCC AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-455 

D 108 N 109 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air, condensation, raw water, waste water 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for In Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.D1.S-457b VIII.D1.S-457d VIII.D1.S-457e VIII.D2.S-457b VIII.D2.S-457d VIII.D2.S-457e VIII.E.S-457b VIII.E.S-457d VIII.E.S-457e VIII.F.S-457b VIII.F.S-457d VIII.F.S-457e VIII.G.S-457b VIII.G.S-457d VIII.G.S-457e VIII.H.S-457c 

D 110 D 111 
3.4-42 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 112 BWR/PWR Aluminum 

underground piping, piping components, tanks 

Cracking due to SCC AMP XI.M32, 

"One-Time Inspection," AMP XI.M41, "Buried and Underground Piping and Tanks," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.H.S-460a VIII.H.S-460b VIII.H.S-460c 

D 113 N 114 BWR/PWR Titanium heat 

exchanger tubes exposed to treated water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.S-462 

VIII.F.S-462 VIII.G.S-462 

N 115 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to treated water 

None None No VIII.I.S-463 

N 116 BWR/PWR Titanium heat 

exchanger tubes exposed to closedcycle cooling water 

Cracking due to SCC, reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.A.S-464 

VIII.E.S-464 VIII.F.S-464 VIII.G.S-464 

N 117 BWR/PWR Aluminum piping, 

piping components, tanks exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.S-466 

D 118 
3.4-43 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 119 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.H.S-468a VIII.H.S-468b VIII.H.S-468c VIII.H.S-468d 

N 120 BWR/PWR Aluminum piping, 

piping components, tanks exposed to raw water, waste water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Outdoor and Large Atmospheric Metallic Storage Tanks," AMP XI.M32, "One-Time Inspection," AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," or AMP XI.M42, "Internal Coatings/Linings for InScope Piping, Piping Components, Heat Exchangers, and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.E.S-469a VIII.E.S-469b VIII.E.S-469c VIII.E.S-469d VIII.E.S-469e 

D 121 
3.4-44 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 122 BWR/PWR Elastomer piping, 

piping components, seals exposed to air 

Loss of material due to wear AMP XI.M36, 

"External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-471 

N 123 BWR/PWR Elastomer piping, 

piping components, seals exposed to air 

Loss of material due to wear AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.D1.S-472 

VIII.D2.S-472 VIII.E.S-472 VIII.G.S-472 

N 124 BWR/PWR PVC piping, piping 

components, tanks exposed to concrete 

None None No VIII.I.S-473 

N 125 BWR/PWR PVC piping, piping 

components, tanks exposed to soil 

Loss of material due to wear AMP XI.M41, 

"Buried and Underground Piping and Tanks" 

No VIII.H.S-474 

N 126 BWR/PWR Titanium (ASTM 

Grades 1, 2, 7, 9, 11, or 12) heat exchanger components other than tubes, piping, piping components exposed to closedcycle cooling water 

None None No VIII.I.S-465 

N 127 BWR/PWR Aluminum piping, 

piping components, tanks exposed to air with borated water leakage 

None None No VIII.I.S-475 

N 128 BWR/PWR Copper alloy piping, 

piping components exposed to concrete 

None None No VIII.I.S-476 

N 129 BWR/PWR Copper alloy piping, 

piping components exposed to soil, underground 

Loss of material due to general, pitting, crevice corrosion, MIC (soil only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.S-477 
3.4-45 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 130 BWR/PWR Titanium piping, 

piping components, heat exchanger components other than tubes exposed to raw water 

Cracking due to SCC, flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.A.S-478a 

VIII.A.S-478b VIII.D1.S-478a VIII.D1.S-478b VIII.D2.S-478a VIII.D2.S-478b VIII.E.S-478a VIII.E.S-478b VIII.F.S-478a VIII.F.S-478b VIII.G.S-478a VIII.G.S-478b 

N 131 PWR Copper alloy (>15% 

Zn) piping, piping components exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No VIII.H.S-479 

N 132 PWR Stainless steel 

piping, piping components, tanks exposed to air with borated water leakage 

None None No VIII.I.S-480 

N 133 BWR/PWR Aluminum piping, 

piping components exposed to raw water 

Flow blockage due to fouling AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.D1.S-481 

VIII.D2.S-481 VIII.E.S-481 VIII.F.S-481 VIII.G.S-481 

N 134 BWR/PWR Titanium (ASTM 

Grades 3, 4, or 5) heat exchanger tubes exposed to raw water 

Cracking due to SCC AMP XI.M38, 

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.D1.S-482 

VIII.D2.S-482 VIII.E.S-482 VIII.F.S-482 
3.4-46 

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in 

Chapter VIII of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited 

Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended GALL-SLR Item 

N 135 BWR/PWR Polymeric piping, 

piping components, ducting, ducting components, seals exposed to air, condensation, raw water, raw water (potable), treated water, waste water, underground, concrete, soil 

Hardening or loss of strength due to polymeric degradation; loss of material due to peeling, delamination, wear; cracking or blistering due to exposure to ultraviolet light, ozone, radiation, or chemical attack; flow blockage due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.D1.S-483b 

VIII.D2.S-483b VIII.E.S-483b VIII.F.S-483b VIII.G.S-483b VIII.H.S-483a 
3.4-47 

Table 3.4-2 AMPs and Additional Guidance Appendices Recommended for 

Aging Management of Steam and Power Conversion System 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP XI.M2 Water Chemistry 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M29 Outdoor and Large Atmospheric Metallic Storage Tanks 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 

3.5-1 

3.5 Aging Management of Containments, Structures, and Component Supports 

Review Responsibilities 

Primary— The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.5.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management programs (AMPs) for containments, structures and components (SC) supports. For 

a recent vintage plant, the information related to containments, supports is contained in Chapter 3, 

“Design of Structures, Components, Equipment, and Systems,” of the plant’s final safety analysis 

report (FSAR), consistent with the “Standard Review Plan for the Review of Safety Analysis 

Reports for Nuclear Power Plants” (NUREG–0800). For older vintage plants, the location of 

applicable information is plant-specific because an older plant’s FSAR may have predated 

NUREG–0800. The scope of this section is containment structures, and safety-related and other 

SC supports. 

The pressurized water reactor (PWR) containment structures consist of concrete (reinforced or 

prestressed) and steel containments. The boiling water reactor (BWR) containment 

structures consist of Mark I, Mark II, and Mark III steel and concrete (reinforced or 

prestressed) containments. 

The safety-related structures (other than containments) are organized into nine groups: Group 1: 

BWR reactor building, PWR shield building, control room/building; Group 2: BWR reactor building 

with steel superstructure; Group 3: auxiliary building, diesel generator building, radwaste building, 

turbine building, switchgear room, yard structures (auxiliary feedwater (AFW) pump house, 

utility/piping tunnels, security lighting poles, manholes, duct banks), station blackout (SBO) 

structures (transmission towers, startup transformer circuit breaker foundation, electrical 

enclosure); Group 4: containment internal structures, excluding refueling canal; Group 5: fuel 

storage facility, refueling canal; Group 6: water-control structures (e.g., intake structure, cooling 

tower, and spray pond); Group 7: concrete tanks and missile barriers; Group 8: steel tank 

foundations and missile barriers; and Group 9: BWR unit vent stack. 

The component supports are organized into seven groups: Group B1.1: supports for American 

Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) Class 1 piping 

and components; Group B1.2: supports for ASME Class 2 and 3 piping and components; 

Group B1.3: supports for ASME Class MC components; Group B2: supports for cable tray, 

conduit, heating, ventilation, and air conditioning (HVAC) ducts, TubeTrack®, instrument tubing, 

non-ASME piping and components; Group B3: anchorage of racks, panels, cabinets, and 

enclosures for electrical equipment and instrumentation; Group B4: supports for miscellaneous 

equipment (e.g., emergency diesel generator (EDG), HVAC components); and Group B5: 

supports for miscellaneous structures (e.g., platforms, pipe whip restraints, jet impingement 

shields, masonry walls). 

The responsible review organization is to review the following subsequent license renewal 

application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 1.2, for review: 
3.5-2 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 AMR results that are not consistent with or not addressed in the GALL-SLR Report 

AMPs 

 Consistent with GALL-SLR Report AMPs 

 Plant-specific AMPs 

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.5.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

3.5.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The AMRs and the AMPs applicable to structures and component supports are described and 

evaluated in Chapters II and III of the GALL-SLR Report. 

The applicant’s SLRA should provide sufficient information so that the reviewer is able to confirm 

that the specific SLRA AMR item and the associated SLRA AMP are consistent with the cited 

GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

consistent with the GALL-SLR Report AMR item to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

capable of managing the effects of aging as adequately as the AMP recommended by the 

GALL-SLR Report. 

3.5.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria defined in Section 3.5.2.1 need to be applied first for all of the 

AMRs and AMPs as part of this section. In addition, if the GALL-SLR Report AMR item to which 

the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply for each of the following aging effect/aging mechanism combinations. 

Refer to Table 3.5-1, comparing the “Further Evaluation Recommended” column and the 

“GALL-SLR Item” column, for the AMR items that reference the following subsections. 
3.5-3 

3.5.2.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 

3.5.2.2.1.1 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 

Cracking and distortion due to increased stress levels from settlement could occur in PWR and 

BWR concrete and steel containments. The existing program relies on ASME Code Section XI, 

Subsection IWL to manage these aging effects. Also, reduction of foundation strength and 

cracking, due to differential settlement and erosion of porous concrete subfoundations could occur 

in all types of PWR and BWR containments. The existing program relies on the structures 

monitoring program to manage these aging effects. However, some plants may rely on a 

dewatering system to lower the site groundwater level. If the plant’s current licensing basis (CLB) 

credits a dewatering system to control settlement, further evaluation is recommended to verify 

the continued functionality of the dewatering system during the subsequent period of 

extended operation. 

3.5.2.2.1.2 Reduction of Strength and Modulus Due to Elevated Temperature 

Reduction of strength and modulus of concrete due to elevated temperatures could occur in PWR 

and BWR concrete and steel containments. The implementation of 10 CFR 50.55a and ASME 

Code Section XI, Subsection IWL would not be able to identify the reduction of strength and 

modulus of concrete due to elevated temperature. Subsection CC-3440 of ASME Code 

Section III, Division 2, specifies the concrete temperature limits for normal operation or any other 

long-term period. Further evaluation is recommended of a plant-specific AMP if any portion of the 

concrete containment components exceeds specified temperature limits {i.e., general area 

temperature greater than 66 °C (Celsius) [150 °F (Fahrenheit)] and local area temperature greater 

than 93 °C (200 °F)}. Higher temperatures may be allowed if tests and/or calculations are 

provided to evaluate the reduction in strength and modulus of elasticity and these reductions are 

applied to the design calculations.  Acceptance criteria are described in Branch Technical Position 

(BTP) RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.2.2.1.3 Loss of Material Due to General, Pitting and Crevice Corrosion 

1. Loss of material due to general, pitting, and crevice corrosion could occur in steel 

elements of inaccessible areas for all types of PWR and BWR containments. The 

existing program relies on ASME Code Section XI, Subsection IWE, and 

10 CFR Part 50, Appendix J AMPs, to manage this aging effect. Further evaluation is 

recommended of plant-specific programs to manage this aging effect if corrosion is 

indicated from the IWE examinations. Acceptance criteria are described in BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 

2. Loss of material due to general, pitting, and crevice corrosion could occur in steel torus 

shell of Mark I containments. The existing program relies on ASME Code Section XI, 

Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. If 

corrosion is significant, recoating of the torus is recommended. Acceptance criteria are 

described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3. Loss of material due to general, pitting, and crevice corrosion could occur in 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 
3.5-4 

containments. The existing program relies on ASME Code Section XI, Subsection IWE 

to manage this aging effect. Further evaluation is recommended of plant-specific 

programs to manage this aging effect if corrosion is significant. Acceptance criteria are 

described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.2.2.1.4 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature 

Loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for PWR 

prestressed concrete containments and BWR Mark II prestressed concrete containments is a 

time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed in 

Section 4.5, “Concrete Containment Unbonded Tendon Pre-stress Analysis,” and/or Section 4.7 

“Other Plant-Specific Time-Limited Aging Analyses,” of this SRP-SLR. 

3.5.2.2.1.5 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue, cyclical loading, or cyclical displacement of metal 

liner, metal plates, suppression pool steel shells (including welded joints) and penetrations 

(including personnel airlock, equipment hatch, control rod drive (CRD) hatch, 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 may be TLAAs as defined in 10 CFR 54.3. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The evaluation of 

this TLAA is addressed in Section 4.6, “Containment Liner Plates, Metal Containments, and 

Penetrations Fatigue Analysis,” and for cases of plant-specific components, in Section 4.7 “Other 

Plant-Specific Time-Limited Aging Analyses,” of this SRP-SLR. For plant-specific cumulative 

usage factor calculations, the method used is appropriately defined and discussed in the 

applicable TLAAs. 

3.5.2.2.1.6 Cracking Due to Stress Corrosion Cracking 

Stress corrosion cracking (SCC) of stainless steel (SS) penetration sleeves, penetration bellows,

vent line bellows, suppression chamber shell (interior surface), and dissimilar metal welds could 

occur in PWR and/or BWR containments. The existing program relies on ASME Code Section XI, 

Subsection IWE and10 CFR Part 50, Appendix J, to manage this aging effect. Further evaluation, 

including consideration of SCC susceptibility and applicable operating experience (OE) related to 

detection, is recommended of additional appropriate examinations/evaluations implemented to 

detect this aging effect for these SS components and dissimilar metal welds. 

3.5.2.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw 

Loss of material (scaling, spalling) and cracking due to freeze-thaw could occur in inaccessible 

areas of PWR and BWR concrete containments. Further evaluation is recommended of this aging 

effect for plants located in moderate to severe weathering conditions. 

3.5.2.2.1.8 Cracking Due to Expansion From Reaction With Aggregates 

Cracking due to expansion from reaction with aggregates could occur in inaccessible areas of 

concrete elements of PWR and BWR concrete and steel containments. The GALL-SLR Report 

recommends further evaluation to determine if a plant-specific aging management program is 

required to manage this aging effect. Acceptance criteria are described in BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 
3.5-5 

3.5.2.2.1.9 Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide 

and Carbonation 

Increase in porosity and permeability due to leaching of calcium hydroxide and carbonation could 

occur in inaccessible areas of concrete elements of PWR and BWR concrete and steel 

containments. Further evaluation is recommended if leaching is observed in accessible areas that 

impact intended functions. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of 

this SRP-SLR). 

3.5.2.2.2 Safety-Related and Other Structures and Component Supports 

3.5.2.2.2.1 Aging Management of Inaccessible Areas 

1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Groups 1–3, 5 and 7–9 structures. Further 

evaluation is recommended of this aging effect for inaccessible areas of these Groups of 

structures for plants located in moderate to severe weathering conditions. 

2. Cracking due to expansion and reaction with aggregates could occur in inaccessible 

concrete areas for Groups 1–5 and 7–9 structures. Further evaluation is recommended 

of inaccessible areas of these Groups of structures to determine if a plant-specific AMP 

is required to manage this aging effect. 

3. Cracking and distortion due to increased stress levels from settlement could occur in 

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 could occur in below-grade inaccessible concrete areas of 

Groups 1–3, 5–9 structures. The existing program relies on structure monitoring 

programs to manage these aging effects. Some plants may rely on a dewatering system 

to lower the site groundwater level. If the plant’s CLB credits a dewatering system, 

verification is recommended of the continued functionality of the dewatering system 

during the subsequent period of extended operation. No further evaluation is 

recommended if this activity is included in the scope of the applicant’s structures 

monitoring program. 

4. Increase in porosity and permeability, and loss of strength due to leaching of calcium 

hydroxide and carbonation could occur in below-grade inaccessible concrete areas of 

Groups 1–5 and 7–9 structures. Further evaluation is recommended if leaching is 

observed in accessible areas that impact intended functions. 

3.5.2.2.2.2 Reduction of Strength and Modulus Due to Elevated Temperature 

Reduction of strength and modulus of concrete due to elevated temperatures could occur in PWR 

and BWR Group 1–5 concrete structures. For any concrete elements that exceed specified 

temperature limits, further evaluations are recommended. Appendix A of American Concrete 

Institute (ACI) 349-85 specifies the concrete temperature limits for normal operation or any other 

long-term period. The temperatures shall not exceed 66 °C (150 °F) except for local areas, which 

are allowed to have increased temperatures not to exceed 93 °C (200°F). Further evaluation is 

recommended of a plant-specific program if any portion of the safety-related and other concrete 

structures exceeds specified temperature limits [i.e., general area temperature greater than 66 °C 

(150°F) and local area temperature greater than 93 °C (200 °F)]. Higher temperatures may be 
3.5-6 

allowed if tests and/or calculations are provided to evaluate the reduction in strength and modulus 

of elasticity and these reductions are applied to the design calculations.  The acceptance criteria 

are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures 

Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging 

effect combinations as identified below, whether or not they are covered by inspections in 

accordance with the GALL-SLR Report, AMP XI.S7, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” or Federal Energy Regulatory Commission 

(FERC)/U.S. Army Corp of Engineers dam inspection and maintenance procedures. 

1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Group 6 structures. Further evaluation is 

recommended of this aging effect for inaccessible areas for plants located in moderate 

to severe weathering conditions. 

2. Cracking due to expansion and reaction with aggregates could occur in inaccessible 

concrete areas of Group 6 structures. Further evaluation is recommended to determine 

if a plant-specific AMP is required to manage this aging effect. Acceptance criteria are 

described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3. Increase in porosity and permeability and loss of strength due to leaching of calcium 

hydroxide and carbonation could occur in inaccessible areas of concrete elements of 

Group 6 structures. Further evaluation is recommended if leaching is observed in 

accessible areas that impact intended functions. Acceptance criteria are described in 

BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.2.2.2.4 Cracking Due to Stress Corrosion Cracking, and Loss of Material Due to Pitting 

and Crevice Corrosion 

Cracking due to SSC and loss of material due to pitting and crevice corrosion could occur in 

(a) Group 7 and 8 SS tank liners exposed to standing water; and (b) SS and aluminum alloy 

support members; welds; bolted connections; or support anchorage to building structure exposed 

to air or condensation (see SRP-SLR Sections 3.2.2.2.2, 3.2.2.2.4, 3.2.2.2.8, and 3.2.2.2.10 for 

background information). 

For Group 7 and 8 SS tank liners exposed to standing water, further evaluation is recommended 

of plant-specific programs to manage these aging effects. The acceptance criteria are described 

in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

For SS and aluminum alloy support members; welds; bolted connections; support anchorage to 

building structure exposed to air or condensation, the plant-specific OE and condition of the SS 

and aluminum alloy components are evaluated to determine if the plant-specific air or 

condensation environments are aggressive enough to result in loss of material or cracking after 

prolonged exposure. The aging effects of loss of material and cracking in SS and aluminum alloy 

components is not applicable and does not require management if (a) the plant-specific OE does 

not reveal a history of pitting or crevice corrosion or cracking and (b) a one-time inspection 

demonstrates that the aging effects are not occurring or that an aging effect is occurring so slowly 

that it will not affect the intended function of the components during the subsequent period of 

extended operation. The applicant documents the results of the plant-specific OE review in the 
3.5-7 

SLRA. Visual inspections conducted in accordance with GALL-SLR Report AMP XI.M32, 

“One-Time Inspection,” are an acceptable method to demonstrate that the aging effects are not 

occurring at a rate that affects the intended function of the components. One-time inspections are 

conducted between the 50th and 60th year of operation, as recommended by the “detection of 

aging effects” program element in AMP XI.M32. If loss of material or cracking has occurred and is 

sufficient to potentially affect the intended function of SS or aluminum alloy support members; 

welds; bolted connections; or support anchorage to building structure, either: (a) enhancing the 

applicable AMP (i.e., GALL-SLR Report AMP XI.S3, “ASME Section XI, Subsection IWF,” or 

AMP XI.S6, “Structures Monitoring”); (b) conducting a representative sample inspection consistent 

with GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components;” 

or (c) developing a plant-specific AMP are acceptable programs to manage loss of material or 

cracking (as applicable). Tempers have been specifically developed to improve the SCC 

resistance for some aluminum alloys. Aluminum alloy and temper combinations which are not 

susceptible to SCC when used in structural support applications include 1xxx series, 3xxx series, 

6061-T6x, and 5454-x. For these alloys and tempers, the susceptibility of cracking due to SCC is 

not applicable. If these alloys or tempers have been used, the SLRA states the specific alloy or 

temper used for the applicable in-scope components. 

3.5.2.2.2.5 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue, cyclical loading, or cyclical displacement of 

component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 

component supports are TLAAs as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The evaluation of this 

TLAA is addressed in Section 4.3, “Metal Fatigue Analysis,” and/or Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analyses,” of this SRP-SLR. For plant-specific cumulative 

usage factor calculations, the method used is appropriately defined and discussed in the 

applicable TLAAs. 

3.5.2.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation 

Reduction of strength, loss of mechanical properties, and cracking due to irradiation could occur in 

PWR and BWR Group 4 concrete structures that are exposed to high levels of neutron and 

gamma radiation. These structures include the reactor (primary/biological) shield wall, the 

sacrificial shield wall, and the reactor vessel support/pedestal structure. Data related to the 

effects and significance of neutron and gamma radiation on concrete mechanical and physical 

properties is limited, especially for conditions (dose, temperature, etc.) representative of 

light-water reactor (LWR) plants. However, based on literature review of existing research, 

radiation fluence limits of 1 × 1019 neutrons/cm2 neutron radiation and 1 × 108 Gy (1 × 1010 rad) 

gamma dose are considered conservative radiation exposure levels beyond which concrete 

material properties may begin to degrade markedly (Ref. 17, 18, 19). 

Further evaluation is recommended of a plant-specific program to manage aging effects of 

irradiation if the estimated (calculated) fluence levels or irradiation dose received by any portion of 

the concrete from neutron (fluence cutoff energy E > 0.1 MeV) or gamma radiation exceeds the 

respective threshold level during the subsequent period of extended operation or if plant-specific 

OE of concrete irradiation degradation exists that may impact intended functions. Higher fluence 

or dose levels may be allowed in the concrete if tests and/or calculations are provided to evaluate 

the reduction in strength and/or loss of mechanical properties of concrete from those fluence 

levels, at or above the operating temperature experienced by the concrete, and the effects are 

applied to the design calculations. Supporting calculations/analyses, test data, and other 
3.5-8 

technical basis are provided to estimate and evaluate fluence levels and the plant-specific 

program. The acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR ). 

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR). 

3.5.2.2.4 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.5.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and are based on the program elements 

of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs credited in the 

SLRA to confirm consistency with the GALL-SLR Report AMPs identified in Chapter X, “Aging 

Management Programs That May Be Used to Demonstrate Acceptability of Time-Limited Aging 

Analyses in Accordance With 10 CFR 54.21(c)(1)(iii),” and Chapter XI, “Chapter XI—Aging 

Management Programs.” 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

SLRA AMP, the reviewer identifies a difference from the GALL-SLR Report AMP that should have 

been identified as an exception to the GALL-SLR Report AMP, this difference should be reviewed 

and properly dispositioned. The reviewer should document the disposition of all SLRA-defined 

exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP to 

be declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. 

The reviewer is to confirm both that the enhancement, when implemented, would allow the 

existing SLRA AMP to be consistent with the GALL-SLR Report AMP and that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the subsequent 

period of extended operation. The reviewer should document the disposition of all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.5.2.5 Final Safety Analysis Report Supplement 

The summary description of the programs and activities for managing the effects of aging for the 

subsequent period of extended operation in the FSAR Supplement should be sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 
3.5-9 

should contain information associated with the bases for determining that aging effects are 

managed during the subsequent period of extended operation. The description should also 

contain any future aging management activities, including enhancements and commitments, to be 

completed before the subsequent period of extended operation. Table X-01 and Table XI-01 of 

the GALL-SLR Report provide examples of the type of information to be included in the FSAR 

Supplement. Table 3.5-2 lists the programs that are applicable for this SRP-SLR subsection. 

3.5.3 Review Procedures 

For each area of review, the review procedures below are to be followed. 

3.5.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to GALL-SLR in its SLRA. In 

making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects have been addressed based on the staff’s review of industry and 

plant-specific OE. 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review requires the reviewer to confirm 

that the applicant has identified those aging effects for the SC supports that are contained in the 

GALL-SLR Report as applicable to its plant. 

3.5.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Section 3.5.3.1 need to be applied first for all of the AMRs 

and AMPs provided in this section. In addition, if the GALL-SLR AMR item to which the SLRA 

AMR item is compared identifies that further evaluation is recommended, then additional criteria 

apply for each of the following aging effect/aging mechanism combinations. 

3.5.3.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 

3.5.3.2.1.1 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 

Further evaluation is recommended of aging management of (1) cracking and distortion due to 

increases in component stress level from settlement for PWR and BWR concrete and steel 

containments and (2) reduction of foundation strength and cracking due to differential settlement 

and erosion of porous concrete subfoundations for all types of PWR and BWR containments if a 

dewatering system is relied upon to control settlement. The reviewer reviews and confirms that, if 

the applicant credits a dewatering system in its CLB, the applicant has committed to monitor 

the functionality of the dewatering system under the applicant’s ASME Code Section XI, 
3.5-10 

Subsection IWL or the structures monitoring program. If not, the reviewer evaluates the 

plant-specific program for monitoring the dewatering system during the subsequent period of 

extended operation. 

3.5.3.2.1.2 Reduction of Strength and Modulus Due to Elevated Temperature 

Further evaluation is recommended of programs to manage reduction of strength and modulus of 

concrete due to elevated temperature for PWR and BWR concrete and steel containments. The 

implementation of ASME Code Section XI, Subsection IWL examinations and 10 CFR 50.55a 

would not be able to detect the reduction of concrete strength and modulus due to elevated 

temperature and also notes that no mandated aging management exists for managing this 

aging effect. 

A plant-specific evaluation should be performed if any portion of the concrete containment 

components exceeds specified temperature limits [i.e., general temperature greater than 66 °C 

(150 °F) and local area temperature greater than 93 °C (200 °F)]. Higher temperatures may be 

allowed if tests and/or calculations are provided to evaluate the reduction in strength and modulus 

of elasticity and these reductions are applied to the design calculations. The reviewer reviews 

and confirms that the applicant’s discussion in the renewal application indicates that the affected 

PWR and BWR containment components are not exposed to a temperature that exceeds the 

temperature limits. If active cooling is relied upon to maintain acceptable temperatures, then the 

reviewer ensures that the aging effects associated with the cooling system are being properly 

managed or temperatures are being monitored to identify a problem with the cooling system. If 

the limits are exceeded the reviewer reviews the technical basis (i.e., tests and/or calculations) 

provided by the applicant to justify the higher temperature. Otherwise, the reviewer reviews the 

applicant’s proposed programs to ensure that the effects of elevated temperature will be 

adequately managed during the subsequent period of extended.

3.5.3.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion 

1. The GALL-SLR Report identifies programs to manage loss of material due to general, 

pitting, and crevice corrosion in accessible and inaccessible areas of the steel elements 

in drywell and torus or the steel liner and integral attachments for all types of PWR and 

BWR containments. The AMP consists of ASME Code Section XI, Subsection IWE, and 

10 CFR Part 50, Appendix J, leak tests. Subsection IWE exempts from examination 

portions of the containments that are inaccessible, such as embedded or inaccessible 

portions of steel liners and steel elements in drywell and torus, and integral attachments. 

To cover the inaccessible areas, 10 CFR 50.55a(b)(2)(ix) requires that the applicant 

evaluate the acceptability of inaccessible areas when conditions exist in accessible areas 

that could indicate the presence of, or result in, degradation to such inaccessible areas. In 

addition, further evaluation of plant-specific programs to manage the aging effects for 

inaccessible areas is recommended if the following cannot be satisfied: (1) concrete 

meeting the requirements of ACI 318 or ACI 349 (low water-to-cement ratio, low 

permeability, and adequate air entrainment) as cited in NUREG–1557 and the guidance of 

ACI 201.2R, as applicable, was used for the containment concrete in contact with the 

embedded containment shell or liner; (2) 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; (3) 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; and (4) borated water spills and water ponding on 
3.5-11 

the concrete floor are common and when detected are cleaned up or diverted to a sump in 

a timely manner. OE has identified significant corrosion in some plants. If any of the 

above conditions cannot be satisfied, then a plant-specific AMP for corrosion is necessary. 

The reviewer reviews the applicant’s proposed AMP to confirm that, where appropriate, an 

effective inspection program has been developed and implemented to ensure that the 

aging effects in inaccessible areas are adequately managed. 

2. The GALL-SLR Report identifies programs to manage loss of material due to general, 

pitting, and crevice corrosion in steel torus shell of Mark I containments. The AMP 

consists of ASME Code Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J, 

leak tests. In addition, further evaluation is recommended of plant-specific programs to 

manage the aging effects if corrosion is significant. Further evaluation of torus shell 

corrosion is warranted as a result of industry-wide OE that identified a number of 

incidences of torus corrosion. The reviewer reviews the applicant’s proposed AMP to 

confirm that, where appropriate, an effective inspection program has been developed 

and implemented to ensure that the aging effects are adequately managed. A 

plant-specific program may include the recoating of the torus, if necessary. 

3. The GALL-SLR Report identifies programs to manage loss of material due to general, 

pitting, and crevice corrosion in steel torus ring girders and downcomers of Mark I 

containments, suppression chambers and downcomers of Mark II containments, and 

interior surface of suppression chamber shell of Mark III containments. GALL-SLR 

Report AMP XI.S1, “ASME Section XI, Subsection IWE,” is recommended for aging 

management. In addition, further evaluation of plant-specific programs is recommended 

to manage the aging effects if plant OE identified significant corrosion of the torus ring 

girders, downcomers and suppression chambers. 

3.5.3.2.1.4 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature 

Loss of prestress is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed in Section 4.5, 

“Concrete Containment Unbonded Tendon Prestress Analysis,” or Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analyses,” of this SRP-SLR. 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Sections 4.5 and/or 4.7 (as applicable) to determine whether the applicant has 

provided a sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria 

in 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

3.5.3.2.1.5 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue, cyclical loading, or cyclical displacement included in 

the CLB for the metal liner, metal plates, suppression pool steel shells (including welded joints) 

and penetrations (including personnel airlock, equipment hatch, CRD hatch, 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 are TLAAs as defined in 10 CFR 54.3. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The evaluation of this 

TLAA is addressed in Section 4.6, “Containment Liner Plate, Metal Containments, and 

Penetrations Fatigue Analysis,” and for cases of plant-specific components, in Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analyses,” of this SRP-SLR. 
3.5-12 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Sections 4.6 or 4.7 (as applicable) to determine whether the applicant has provided 

a sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria in 

10 CFR 54.21(c)(1)(i), (ii), or (iii). This includes staff’s review of those cumulative usage factor 

analyses that qualify as TLAAs based on plant-specific calculation methods. 

3.5.3.2.1.6 Cracking Due to Stress Corrosion Cracking 

Further evaluation is recommended of programs to manage cracking due to SCC in SS 

penetration sleeves, penetration bellows, vent line bellows, suppression chamber shell (interior 

surface), and dissimilar metal welds in PWR and/or BWR containments. Transgranular stress 

corrosion cracking (TGSCC) is a concern for dissimilar metal welds. In the case of bellows 

assemblies, SCC may cause aging effects particularly if the material is not shielded from a 

corrosive environment. Containment inservice inspection (ISI) IWE and leak rate testing may not 

be sufficient to detect cracks, especially for dissimilar metal welds. Additional appropriate 

examinations to detect SCC in the listed SS components and dissimilar metal welds, considering 

SCC susceptibility and applicable OE (e.g., cracking of two-ply bellows) related to detection, are 

recommended to address this issue. The reviewer reviews and evaluates the applicant’s 

proposed programs to confirm that adequate inspection methods will be implemented to ensure 

that cracks are detected. 

3.5.3.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw 

Further evaluation is recommended of programs to manage loss of material (scaling, spalling) and 

cracking due to freeze-thaw for concrete elements of PWR and BWR containments. Containment 

ISI Subsection IWL may not be sufficient for plants located in moderate to severe weathering 

conditions. Evaluation is needed for plants that are located in moderate to severe weathering 

conditions (weathering index >100 day-inch/yr) (NUREG–1557). The weathering index for the 

continental United States is shown in American Society for Testing and Materials (ASTM) C33-90, 

Figure 1. A plant-specific program is not required if documented evidence confirms that the 

existing concrete had air content of 3 percent to 8 percent (including tolerance) and subsequent 

inspection of accessible areas did not exhibit degradation related to freeze-thaw. Such 

inspections are considered a part of the evaluation. The reviewer reviews and confirms that the 

applicant has satisfied the recommendations for inaccessible concrete. Otherwise, the reviewer 

reviews the applicant’s proposed AMP to verify that, where appropriate, an effective inspection 

program has been developed and implemented to ensure that these aging effects in inaccessible 

areas for plants located in moderate to severe weathering conditions are adequately managed. 

3.5.3.2.1.8 Cracking Due to Expansion from Reaction With Aggregates 

Further evaluation is recommended of programs to manage cracking due to expansion from 

reaction with aggregates in inaccessible areas of concrete elements of PWR and BWR concrete 

and steel containments. A plant-specific AMP is necessary if (1) reactivity tests or petrographic 

examinations of concrete samples identify reaction with aggregates, or (2) accessible concrete 

exhibits visual indications of aggregate reactions, such as “map” or “patterned” cracking, 

alkali-silica gel, exudations, surface staining, expansion causing structural deformation, relative 

movement or displacement, or misalignment/distortion of attached components. The reviewer 

confirms that the applicant has not identified one of the above conditions. Otherwise, the reviewer 

reviews the applicant’s proposed AMP or plant-specific evaluation to verify that, an effective 

evaluation or inspection program has been developed and implemented to ensure that this aging 

effect in inaccessible areas is adequately managed. 
3.5-13 

3.5.3.2.1.9 Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide 

and Carbonation 

Further evaluation is recommended of programs to manage increase in porosity and permeability 

due to leaching of calcium hydroxide and carbonation in inaccessible areas of PWR and BWR 

concrete and steel containments. A plant-specific AMP is not required, even if reinforced concrete 

is exposed to flowing water 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 reviewer confirms that the applicant has satisfied these conditions. 

Otherwise, the reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, 

an effective inspection program has been developed and implemented to ensure that this aging 

effect in inaccessible areas is adequately managed. 

3.5.3.2.2 Safety-Related and Other Structures, and Component Supports 

3.5.3.2.2.1 Aging Management of Inaccessible Areas 

1. Further evaluation is recommended of programs to manage loss of material (spalling, 

scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas of 

Groups 1–3, 5, and 7–9 structures. Structure monitoring programs may not be sufficient 

for plants located in moderate to severe weathering conditions. Further evaluation is 

needed for plants that are located in moderate to severe weathering conditions 

(weathering index >100 day-inch/yr) (NUREG–1557). The weathering index for the 

continental United States is shown in ASTM C33-90, Figure 1. A plant-specific program 

is not required if documented evidence confirms that the existing concrete had air 

content of 3 percent to 8 percent and subsequent inspection did not exhibit degradation 

related to freeze-thaw. Such inspections should be considered a part of the evaluation. 

The reviewer confirms that the applicant has satisfied these conditions. Otherwise, the 

reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, an 

effective inspection program has been developed and implemented to ensure that this 

aging effect in inaccessible areas for plants located in moderate to severe weathering 

conditions is adequately managed. 

2. Further evaluation is recommended to determine if a plant-specific program is required 

to manage cracking due to expansion from reaction with aggregates in inaccessible 

concrete areas of Groups 1–5 and 7–9 structures. A plant-specific evaluation or 

program is required if (1) reactivity tests or petrographic examinations of concrete 

samples identify reaction with aggregates, or (2) accessible concrete exhibits visual 

indications of aggregate reactions, such as “map” or “patterned” cracking, alkali-silica gel 

exudations, surface staining, expansion causing structural deformation, relative 

movement or displacement, or misalignment/distortion of attached components. The 

reviewer confirms that the applicant has not identified any of the above conditions. 

Otherwise, the reviewer reviews the applicant’s proposed AMP or plant-specific 

evaluation to verify that, an effective evaluation or inspection program has been 

developed and implemented to ensure that the aging effect is adequately managed. 

3. Further evaluation is recommended of aging management of (a) cracking and distortion 

due to increased stress levels from settlement for inaccessible concrete areas of 

structures for all Groups and (b) reduction of foundation strength, and cracking due to 

differential settlement and erosion of porous concrete subfoundations for inaccessible 
3.5-14 

concrete areas of Groups 1–3, and 5–9 structures if a dewatering system is relied upon 

to manage the aging effect. The reviewer confirms that, if the applicant’s plant credits a 

dewatering system in its CLB, the applicant has committed to monitor the functionality of 

the dewatering system under the applicant’s structures monitoring program. If not, the 

reviewer reviews and evaluates the plant-specific program for monitoring the dewatering 

system during the subsequent period of extended operation. 

4. Further evaluation is recommended of programs to manage increase in porosity and 

permeability due to leaching of calcium hydroxide and carbonation in below-grade 

inaccessible concrete areas of Groups 1–5, and 7–9 structures. A plant-specific AMP is 

not required for the reinforced concrete exposed to flowing water if (1) there is evidence 

in the accessible areas that the flowing water has not caused leaching of calcium 

hydroxide 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 reviewer confirms that the applicant has satisfied 

these conditions. Otherwise, the reviewer reviews the applicant’s proposed AMP to 

verify that, where appropriate, an effective inspection program has been developed 

and implemented to ensure that this aging effect in inaccessible areas is 

adequately managed. 

3.5.3.2.2.2 Reduction of Strength and Modulus Due to Elevated Temperature 

Further evaluation is recommended of programs to manage reduction of strength and modulus 

of concrete structures due to elevated temperature for PWR and BWR safety-related and 

other structures. 

A plant-specific evaluation should be performed if any portion of the concrete Groups 1–5 

structures exceeds specified temperature limits [i.e., general temperature greater than 66 °C 

(150 °F) and local area temperature greater than 93 °C (200 °F)]. Higher temperatures may be 

allowed if tests and/or calculations are provided to evaluate the reduction in strength and modulus 

of elasticity and these reductions are applied to the design calculations. The reviewer reviews 

and confirms that the applicant’s discussion in the renewal application indicates that the affected 

Groups 1–5 structures are not exposed to temperature that exceeds the temperature limits. If 

active cooling is relied upon to maintain acceptable temperatures, then the reviewer ensures that 

the aging effects associated with the cooling system are being properly managed or temperatures 

are being monitored to identify a problem with the cooling system. If the limits are exceeded, the 

reviewer reviews the technical basis (i.e., tests and/or calculations) provided by the applicant to 

justify the higher temperature. Otherwise the reviewer reviews the applicant’s proposed programs 

on a case-by-case basis to ensure that the effects of elevated temperature will be adequately 

managed during the subsequent period of extended operation.

3.5.3.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures 

Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging 

effect combinations as identified below, whether or not they are covered by inspections in 

accordance with GALL-SLR Report AMP XI.S7, or FERC/US Army Corp of Engineers dam 

inspection and maintenance procedures. 

1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Group 6 structures. Further evaluation is 

needed for plants that are located in moderate to severe weathering conditions 
3.5-15 

(weathering index >100 day-inch/yr) (NUREG–1557, Ref. 15). The weathering index for 

the continental U.S. is shown in ASTM C33-90, Figure 1. A plant-specific program is not 

required if documented evidence confirms that the existing concrete had air content of 

3 percent to 8 percent and subsequent inspection of accessible areas did not exhibit 

degradation related to freeze-thaw. Such inspections should be considered a part of the 

evaluation. The reviewer reviews and confirms that the applicant has satisfied these 

conditions. Otherwise, the reviewer reviews the applicant’s proposed AMP to determine 

that, where appropriate, an effective inspection program has been developed and 

implemented to ensure that this aging effect in inaccessible areas for plants located in 

moderate to severe weathering conditions will be adequately managed. 

2. Cracking due to expansion from reaction with aggregates could occur in inaccessible 

concrete areas of Group 6 structures. Further evaluation is recommended to determine 

if a plant-specific program is required to manage the aging effect. A plant-specific 

evaluation or program is required if (1) reactivity tests or petrographic examinations of 

concrete samples identify reaction with aggregates, or (2) accessible concrete exhibits 

visual indications of aggregate reactions, such as “map” or “patterned” cracking, 

alkali-silica gel exudations, surface staining, expansion causing structural deformation, 

relative movement or displacement, or misalignment/distortion of attached components. 

The reviewer confirms that the applicant has not identified any of the above conditions. 

Otherwise, the reviewer reviews the applicant’s proposed AMP or plant-specific 

evaluation to verify that, an effective evaluation or inspection program has been 

developed and implemented to ensure that the aging effect will be adequately managed. 

3. Increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation could occur in below-grade inaccessible concrete areas of Group 6 

structures. Further evaluation is recommended to determine if a plant-specific program 

is required to manage the aging effect. A plant-specific program is not required for the 

reinforced structures exposed to flowing water 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 

reviewer confirms that the applicant has satisfied these conditions. Otherwise, the 

reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, an 

effective inspection program has been developed and implemented to ensure that this 

aging effect in inaccessible areas will be adequately managed. 

3.5.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and 

Crevice Corrosion 

Further evaluation is recommended of plant-specific programs to manage cracking due to SCC 

and loss of material due to pitting and crevice corrosion for SS tank liners exposed to standing 

water. The reviewer reviews the applicant’s proposed AMP on a case-by-case basis to 

ensure that the intended functions will be maintained during the subsequent period of 

extended operation. 

The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

and crevice corrosion and cracking due to SCC in SS and aluminum alloy support members; 

welds; bolted connections; or support anchorage to building structure exposed to any air, 

condensation, or underground environment where the presence of sufficient halides 

(e.g., chlorides) and moisture is possible; or in the vicinity of potentially transportable halogens. 
3.5-16 

The possibility of these aging effects also extends to indoor components located in close proximity 

to sources of outdoor air (e.g., components near intake vents). 

The reviewer independently verifies the sufficiency of the applicant’s evaluation of plant-specific 

OE. If the review of plant-specific OE reveals loss of material due to pitting or crevice corrosion or 

cracking due to SCC in SS or aluminum alloys, the reviewer determines whether an adequate 

program is credited to manage the aging effect. If the review of plant-specific OE reveals that loss 

of material due to pitting and crevice corrosion and cracking due to SCC is not applicable, the 

reviewer verifies that AMP XI.M32, “One-Time Inspection,” is cited for all applicable AMR 

line items. 

An applicant may refine its OE search, and subsequent one-time inspections, by binning 

plant-specific environments into subcategories. For example, the OE search could be based on 

two environments including outdoor air and indoor air. The results could be that loss of material 

or cracking has occurred in the outdoor air environment but not the indoor air environment. The 

applicant could further categorize the indoor air locations as those where leakage could impinge 

on a component’s surface (e.g., leakage from mechanical connections) and those where there is 

not a potential for leakage. When the applicant chooses to conduct its OE search in this manner, 

the reviewer is to also confirm that the applicant has adequately addressed the potential for the 

periodic introduction of either moisture or halides from secondary sources. Secondary sources of 

moisture or halides should be considered for all environments including indoor conditioned air. 

Typical secondary sources of moisture or halides include: leakage from mechanical connections; 

leakage into vaults; insulation containing halides; and outdoor air intrusion. Grouping of 

environments consistent with that described in the detection of aging effects program element of 

GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components,” is appropriate. 

3.5.3.2.2.5 Cumulative Fatigue Damage 

Evaluations involving time-dependent fatigue, cyclical loading, or cyclical displacement of support 

members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports are 

TLAAs as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed in 

Section 4.3, “Metal Fatigue Analysis,” and/or Section 4.7, “Other Plant-Specific Time-Limited 

Aging Analyses,” of this SRP-SLR. 

The staff reviews the information on a case-by-case basis consistent with the review procedures 

in SRP-SLR Sections 4.3 and/or 4.7 (as applicable) to determine whether the applicant has 

provided a sufficient basis for dispositioning the TLAAs in accordance with the acceptance criteria 

in 10 CFR 54.21(c)(1)(i), (ii), or (iii). This includes staff’s review of those cumulative usage factor 

analyses that qualify as TLAAs based on plant-specific calculation methods. 

3.5.3.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation 

Further evaluation is recommended of a plant-specific program to manage reduction of strength, 

loss of mechanical properties, and cracking of concrete due to irradiation in PWR and BWR 

Group 4 concrete structures, exposed to high levels of neutron and gamma radiation. These 

structures include the reactor (primary/biological) shield wall, the sacrificial shield wall, and the 

reactor vessel support/pedestal structure. The irradiation mechanism consists of radiation 

interactions with the material and heating due to absorption of radiation energy at the operating 

temperature experienced by the concrete. The intensity of radiation is typically characterized by 
3.5-17 

the measure of its field or fluence. Both neutron and gamma radiation produce internal heating 

from absorption of radiation energy and, at high fluence levels, changes in microstructure and 

certain mechanical properties of concrete (e.g., compressive strength, tensile strength, modulus of 

elasticity) from radiation interactions with the material. Limited data are available in the 

open literature related to the effects and significance of radiation fluences (neutron and 

gamma radiation) on intended functions of concrete structures, especially for conditions 

(dose, temperature, etc.) representative of existing LWR plants. However, based on literature 

review of existing research, fluence limits of 1 × 1019 neutrons/cm2 neutron radiation and 

1 × 108 Gy (1 × 1010 rad) gamma dose are considered conservative radiation exposure levels 

beyond which concrete material properties may begin to degrade markedly. 

Plant-specific calculations/analyses should be performed to identify the neutron (fluence cutoff 

energy E > 0.1 MeV) and gamma fields that develop in any portion of the concrete structures of 

interest at 80 years of operation and compare them to the above threshold limits. The impact of 

any plant-specific OE of concrete irradiation effects on intended functions are evaluated. The 

reviewer reviews these analyses, OE and supporting technical basis (e.g., calculations, test data, 

plant-specific evaluations) on a case-by-case basis. Higher fluence or dose levels may be 

allowed in the concrete if tests and/or calculations are provided to evaluate the reduction in 

strength and/or change in mechanical properties of concrete, if any, from those fluence levels and 

the effects are applied to the design calculations. The reviewer confirms that the applicant’s 

discussion in the SLRA indicates that the affected PWR and BWR concrete components are not 

exposed to neutron and gamma radiation fluence levels that exceed the threshold limits, or are 

otherwise evaluated, for example, the concrete is primarily for shielding and non-structural. The 

reviewer also confirms that the impact of any plant-specific OE of concrete irradiation degradation 

on intended functions is addressed. If the limits are exceeded, the technical basis (i.e., tests 

and/or calculations or evaluations) provided by the applicant to justify higher fluence or dose limits 

is reviewed. Otherwise, the applicant’s proposed plant-specific program and the supporting 

technical basis is reviewed to ensure that the effects of irradiation on the concrete components 

will be adequately managed during the subsequent period of extended operation. 

3.5.3.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMP for subsequent license renewal (SLR) should contain the elements of 

corrective actions, the confirmation process, and administrative controls. Safety-related 

components are covered by 10 CFR Part 50 Appendix B, which is adequate to address these 

program elements. However, Appendix B does not apply to nonsafety-related components that 

are subject to an AMR for SLR. Nevertheless, an applicant has the option to expand the scope of 

its 10 CFR Part 50 Appendix B program to include these components and address these program 

elements. If the applicant chooses this option, the reviewer verifies that the applicant has 

documented such a commitment in the FSAR Supplement. If the applicant chooses alternative 

means, the branch responsible for quality assurance should be requested to review the 

applicant’s proposal on a case-by-case basis. 

3.5.3.2.4 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to 

ensure that the AMPs are effective to manage the aging effects for which they are created. The 

AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined 

through the evaluation of OE that the effects of aging may not be adequately managed. 
3.5-18 

Additional information is in Appendix A.4, “Operating Experience for Aging Management 

Programs” of this SRP-SLR. In addition, the reviewer confirms that the applicant has provided an 

appropriate summary description of these activities in the FSAR Supplement. 

3.5.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in their SLRA, has identified applicable aging 

effects, listed the appropriate combination of materials and environments, and credited AMPs that 

will adequately manage the aging effects. The AMP credited by the applicant could be an AMP 

that is described and evaluated in the GALL-SLR Report or a plant-specific program. Review 

procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.5.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP, with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the containments, structures, and component supports are summarized in Table 3.5-1 

of this SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in the 

GALL-SLR Report, Chapters II and III, presenting detailed information summarized by this row. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1.2.3 of this SRP-SLR). 

3.5.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in its FSAR Supplement information for 

aging management of the containments, structures, and component supports. Table 3.5-2 lists 

the AMPs that are applicable for this SRP-SLR subsection. The reviewer also confirms that the 

applicant has provided information for Subsection 3.5.3.3, “Aging Management Review Results 

Not Consistent With or Not Addressed in the Generic Aging Lessons Learned for Subsequent 

License Renewal Report.” 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 
3.5-19 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

3.5.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has demonstrated that the aging effects associated with the 

containments, structures, and component supports components will be 

adequately managed so that the intended functions will be maintained consistent 

with the CLB for the subsequent period of extended operation, as required by 

10 CFR 54.21(a)(3). 

The NRC staff also reviewed the applicable FSAR Supplement program 

summaries and concludes that they adequately describe the AMPs credited 

for managing aging of the containments, structures, and component supports, as 

required by 10 CFR 54.21(d). 

3.5.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.5.6 References 

1. 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

2016. 

2. 10 CFR 50.55a, “Codes and Standards.” Washington, DC: U.S. Nuclear Regulatory 

Commission. 2016. 

3. 10 CFR 50.59, “Changes, Tests, and Experiments.” Washington, DC: U.S. Nuclear 

Regulatory Commission. 2016. 

4. 10 CFR Part 50, Appendix J, “Primary Reactor Containment Leakage Testing for 

Water-Cooled Power Reactors.” Washington, DC: U.S. Nuclear Regulatory Commission. 

2016. 

5. 10 CFR 50.71, “Maintenance of Record, Making of Reports.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016. 
3.5-20 

6. 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

7. 10 CFR 54.4, “Scope.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

8. NRC. Regulatory Guide 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants.” Revision 1. Agencywide Documents Access and Management 

System (ADAMS) Accession No. ML003739392. Washington, DC: U.S. Nuclear 

Regulatory Commission. March 1978. 

9. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. ADAMS Accession 

No. ML051860406. Washington, DC: Nuclear Energy Institute. June 2005. 

10. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components,” Subsection IWL, “Requirements for Class CC Concrete Components of 

Light-Water Cooled Power Plants.” New York, New York: The American Society of 

Mechanical Engineers. 2008. 

11. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components,” Subsection IWE, “Requirements for Class MC and Metallic Liners of Class 

CC Components of Light-Water Cooled Power Plants.” New York, New York: The 

American Society of Mechanical Engineers. 2008. 

12. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components,” Subsection IWF, “Requirements for Class 1, 2, 3, and MC Component 

Supports of Light-Water Cooled Power Plants.” New York, New York: The American 

Society of Mechanical Engineers. 2008. 

13. NEI. NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants.” Revision 2. ADAMS Accession 

No. ML11116A198. Washington, DC: Nuclear Energy Institute. April 1996. 

14. NRC. Regulatory Guide 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants.” Revision 2. Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML003761662. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 31 1997. 

15. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Report addressing License Renewal.” 

Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 

16. ACI. ACI Standard 318, “Building Code Requirements for Reinforced Concrete and 

Commentary.” Farmington Hills, Michigan: American Concrete Institute. 1995. 

17. Hilsdorf, H.K., J. Kropp, and H.J. Koch. “The Effects of Nuclear Radiation on the 

Mechanical Properties of Concrete.” ACI SP 55-10. pp 223-251. Farmington Hills, 

Michigan: American Concrete Institute. 1978. 
3.5-21 

18. NRC. NUREG/CR–7171, “A Review of the Effects of Radiation on Microstructure and 

Properties of Concretes Used in Nuclear Power Plants.” ADAMS Accession 

No. ML13325B077. Washington, DC: U.S. Nuclear Regulatory Commission. 

November 2013. 

19. Field, K.G., Y. Le Pape, and I. Remec. “Perspectives on Radiation Effects in Concrete for 

Nuclear Power Plants–Part I: Quantification of Radiation Exposure and Radiation 

Effects.” Nuclear Engineering and Design. Vol 285. pp 126–143. February 2015. 

20. ACI. ACI Standard 349-85, “Code Requirements for Nuclear Safety-Related Concrete 

Structures.” Farmington Hills, Michigan: American Concrete Institute. 1985. 
3.5-22 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 001 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; buttresses, concrete elements, all 

Cracking and distortion due to increased stress levels from settlement 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.1.1) 

II.A1.CP-101 II.A2.CP-69 II.B1.2.CP-105 II.B2.2.CP-105 II.B3.1.CP-69 II.B3.2.CP-105 

E 002 BWR/PWR Concrete: foundation; 

subfoundation 

Reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete subfoundation 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.1.1) 

II.A1.C-07 II.A2.C-07 II.B1.2.C-07 II.B2.2.C-07 II.B3.1.C-07 II.B3.2.C-07 

M 003 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; buttresses, concrete: containment; wall; basemat, concrete: basemat, concrete fill-in annulus 

Reduction of strength and modulus of elasticity due to elevated temperature (>150°F general; >200°F local) 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.2) 

II.A1.CP-34 II.B1.2.CP-57 II.B2.2.CP-57 II.B3.1.CP-65 II.B3.2.CP-108 

E 004 BWR Steel elements 

(inaccessible areas): drywell shell; drywell head 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.1) 

II.B3.1.CP-113 

E 005 BWR/PWR 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) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.1) 

II.A1.CP-98 II.A2.CP-98 II.B1.2.CP-63 II.B2.1.CP-63 II.B2.2.CP-63 II.B3.2.CP-98 
3.5-23 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 006 BWR Steel elements: torus 

shell 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.2) 

II.B1.1.CP-48 

E 007 BWR Steel elements: torus ring 

girders; downcomers;, Steel elements: suppression chamber shell (interior surface) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

Yes (SRP-SLR Section 3.5.2.2.1.3.3) 

II.B1.1.CP-109 II.B3.1.CP-158 

M 008 BWR/PWR Prestressing system: 

tendons 

Loss of prestress due to relaxation; shrinkage; creep; elevated temperature 

TLAA, SRP-SLR Section 4.5, "Concrete Containment Tendon Prestress," and/or SRP-SLR Section 4.7, "Other PlantSpecific TimeLimited Aging Analyses" 

Yes (SRP-SLR Section 3.5.2.2.1.4) 

II.A1.C-11 II.B2.2.C-11 

M 009 BWR/PWR Metal liner, metal plate, 

personnel airlock, equipment hatch, CRD hatch, 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 

Cumulative fatigue damage due to cyclic loading (Only if CLB fatigue analysis exists) 

TLAA, SRP-SLR Section 4.6, "Containment Liner Plate and Penetration Fatigue Analysis" 

Yes (SRP-SLR Section 3.5.2.2.1.5) 

II.A3.C-13 II.B1.1.C-21 II.B2.1.C-45 II.B2.2.C-48 II.B4.C-13 
3.5-24 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 010 BWR/PWR Penetration sleeves; 

penetration bellows 

Cracking due to SCC AMP XI.S1, 

"ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.6) 

II.A3.CP-38 II.B4.CP-38 

E 011 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.7) 

II.A1.CP-147 II.A2.CP-70 II.B3.2.CP-135 

M 012 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, containment, concrete fill-in annulus 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.8) 

II.A1.CP-67 II.A2.CP-104 II.B1.2.CP-99 II.B2.2.CP-99 II.B3.1.CP-83 II.B3.2.CP-121 

D 013 M 014 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, containment 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.9) 

II.A1.CP-102 II.A2.CP-53 II.B1.2.CP-110 II.B2.2.CP-110 II.B3.1.CP-53 II.B3.2.CP-122 

D 015 M 016 BWR/PWR Concrete (accessible 

areas): basemat, concrete: containment; wall 

Increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to aggressive chemical attack 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-87 

II.A2.CP-72 II.B1.2.CP-106 II.B2.2.CP-106 II.B3.1.CP-72 

D 017 M 018 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-31 

II.A2.CP-51 II.B3.2.CP-52 
3.5-25 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 019 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses, containment; concrete fill-in annulus 

Cracking due to expansion from reaction with aggregates 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-33 

II.A2.CP-58 II.B1.2.CP-59 II.B2.2.CP-59 II.B3.1.CP-66 II.B3.2.CP-60 

M 020 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses, containment 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S2, "ASME Section XI, Subsection IWL" 

No II.A1.CP-32 

II.A2.CP-155 II.B1.2.CP-54 II.B2.2.CP-54 II.B3.1.CP-156 II.B3.2.CP-55 

E 021 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses; reinforcing steel 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-68 

II.A2.CP-74 II.B1.2.CP-79 II.B2.2.CP-79 II.B3.1.CP-74 II.B3.2.CP-88 

D 022 M 023 BWR/PWR Concrete (inaccessible 

areas): basemat; reinforcing steel, dome; wall 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-97 

II.A2.CP-75 II.B1.2.CP-80 II.B2.2.CP-80 II.B3.1.CP-75 II.B3.2.CP-89 

E 024 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, concrete (accessible areas): dome; wall; basemat 

Increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to aggressive chemical attack 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-100 

II.A2.CP-71 II.B3.1.CP-71 II.B3.2.CP-73 II.B3.2.CP-84 

D 025  026 BWR/PWR Moisture barriers 

(caulking, flashing, and other sealants) 

Loss of sealing due to wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.A3.CP-40 

II.B4.CP-40 
3.5-26 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 027 BWR/PWR Metal liner, metal plate, 

airlock, equipment hatch, CRD hatch; penetration sleeves; penetration bellows, steel elements: torus; vent line; vent header; vent line bellows; downcomers, suppression pool shell 

Cracking due to cyclic loading (CLB fatigue analysis does not exist) 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-37 

II.B1.1.CP-49 II.B2.1.CP-107 II.B4.CP-37 

 028 BWR/PWR Personnel airlock, 

equipment hatch, CRD hatch 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.C-16 

II.B4.C-16 

M 029 BWR/PWR Personnel airlock, 

equipment hatch, CRD hatch: locks, hinges, and closure mechanisms 

Loss of leak tightness due to mechanical wear 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-39 

II.B4.CP-39 

 030 BWR/PWR Pressure-retaining bolting Loss of preload due to 

self-loosening 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-150 

II.B4.CP-150 

 031 BWR/PWR Pressure-retaining 

bolting, steel elements: downcomer pipes 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.A3.CP-148 

II.B1.2.CP-117 II.B2.1.CP-117 II.B2.2.CP-117 II.B4.CP-148 

 032 BWR/PWR Prestressing system: 

tendons; anchorage components 

Loss of material due to corrosion 

AMP XI.S2, "ASME Section XI, Subsection IWL" 

No II.A1.C-10 

II.B2.2.C-10 
3.5-27 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 033 BWR/PWR Seals and gaskets Loss of sealing due to 

wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S4, "10 CFR Part 50, Appendix J " 

No II.A3.CP-41 

II.B4.CP-41 

 034 BWR/PWR Service Level I coatings Loss of coating or lining 

integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage 

AMP XI.S8, "Protective Coating Monitoring and Maintenance" 

No II.A3.CP-152 

II.B4.CP-152 

M 035 BWR/PWR Steel elements 

(accessible areas): liner; liner anchors; integral attachments, penetration sleeves, drywell shell; drywell head; drywell shell in sand pocket regions; suppression chamber; drywell; embedded shell; region shielded by diaphragm floor (as applicable) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.1) 

II.A1.CP-35 II.A2.CP-35 II.A3.CP-36 II.B1.1.CP-43 II.B1.2.CP-46 II.B2.1.CP-46 II.B2.2.CP-46 II.B3.1.CP-43 II.B3.2.CP-35 II.B4.CP-36 

M 036 BWR Steel elements: drywell 

head; downcomers 

Loss of material due to mechanical wear, including fretting 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.B1.1.C-23 

II.B1.2.C-23 II.B2.1.C-23 II.B2.2.C-23 

 037 BWR Steel elements: 

suppression chamber (torus) liner (interior surface) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.B1.2.C-49 

II.B2.2.C-49 

M 038 BWR Steel elements: 

suppression chamber shell (interior surface) 

Cracking due to SCC AMP XI.S1, 

"ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.6) 

II.B3.1.C-24 II.B3.2.C-24 
3.5-28 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 039 BWR Steel elements: vent line 

bellows 

Cracking due to SCC AMP XI.S1, 

"ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.6) 

II.B1.1.CP-50 

 040 BWR Unbraced downcomers, 

steel elements: vent header; downcomers 

Cracking due to cyclic loading (CLB fatigue analysis does not exist) 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.B2.1.CP-142 

II.B2.2.CP-64 

E 041 BWR Steel elements: drywell 

support skirt, steel elements (inaccessible areas): support skirt 

None None No II.B1.1.CP-44 

II.B1.2.CP-114 II.B2.1.CP-114 II.B2.2.CP-114 

M 042 BWR/PWR Groups 1-3, 5, 7- 9: 

concrete (inaccessible areas): foundation 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.1) 

III.A1.TP-108 III.A2.TP-108 III.A3.TP-108 III.A5.TP-108 III.A7.TP-108 III.A8.TP-108 III.A9.TP-108 

M 043 BWR/PWR All Groups except Group 

6: concrete (inaccessible areas): all 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.2) 

III.A1.TP-204 III.A2.TP-204 III.A3.TP-204 III.A4.TP-204 III.A5.TP-204 III.A7.TP-204 III.A8.TP-204 III.A9.TP-204 

E 044 BWR/PWR All Groups: concrete: all Cracking and distortion 

due to increased stress levels from settlement 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.2.1.3) 

III.A1.TP-30 III.A2.TP-30 III.A3.TP-30 III.A4.TP-30 III.A5.TP-30 III.A6.TP-30 III.A7.TP-30 III.A8.TP-30 III.A9.TP-30 

D 045 
3.5-29 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 046 BWR/PWR Groups 1-3, 5-9: 

concrete: foundation; subfoundation 

Reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete subfoundation 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.2.1.3) 

III.A1.TP-31 III.A2.TP-31 III.A3.TP-31 III.A5.TP-31 III.A6.TP-31 III.A7.TP-31 III.A8.TP-31 III.A9.TP-31 

M 047 BWR/PWR Groups 1-5, 7-9: concrete 

(inaccessible areas): exterior above- and below-grade; foundation 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.4) 

III.A1.TP-67 III.A2.TP-67 III.A3.TP-67 III.A4.TP-305 III.A5.TP-67 III.A7.TP-67 III.A8.TP-67 III.A9.TP-67 

M 048 BWR/PWR Groups 1-5: concrete: all Reduction of strength and 

modulus due to elevated temperature (>150°F general; >200°F local) 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.2) 

III.A1.TP-114 III.A2.TP-114 III.A3.TP-114 III.A4.TP-114 III.A5.TP-114 

M 049 BWR/PWR Groups 6 - concrete 

(inaccessible areas): exterior above- and below-grade; foundation; interior slab 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.1) 

III.A6.TP-110 

M 050 BWR/PWR Groups 6: concrete 

(inaccessible areas): all 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.2) 

III.A6.TP-220 

M 051 BWR/PWR Groups 6: concrete 

(inaccessible areas): exterior above- and below-grade; foundation; interior slab 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.3) 

III.A6.TP-109 
3.5-30 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 052 BWR/PWR Groups 7, 8 - steel 

components: tank liner 

Cracking due to SCC; Loss of material due to pitting and crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.4) 

III.A7.T-23 III.A8.T-23 

M 053 BWR/PWR Support members; welds; 

bolted connections; support anchorage to building structure 

Cumulative fatigue damage due to cyclic loading (Only if CLB fatigue analysis exists) 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue," and/or Section 4.7 "Other Plant-Specific Time-Limited Aging Analyses" 

Yes (SRP-SLR Section 3.5.2.2.2.5) 

III.B1.1.T-26 III.B1.2.T-26 III.B1.3.T-26 

M 054 BWR/PWR All groups except 6: 

concrete (accessible areas): all 

Cracking due to expansion from reaction with aggregates 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-25 

III.A2.TP-25 III.A3.TP-25 III.A4.TP-25 III.A5.TP-25 III.A6.TP-25 III.A7.TP-25 III.A8.TP-25 III.A9.TP-25 

 055 BWR/PWR Building concrete at 

locations of expansion and grouted anchors; grout pads for support base plates 

Reduction in concrete anchor capacity due to local concrete degradation/ serviceinduced cracking or other concrete aging mechanisms 

AMP XI.S6, "Structures Monitoring" 

No III.B1.1.TP-42 

III.B1.2.TP-42 III.B1.3.TP-42 III.B2.TP-42 III.B3.TP-42 III.B4.TP-42 III.B5.TP-42 
3.5-31 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 056 BWR/PWR Concrete: exterior aboveand below- grade; 

foundation; interior slab 

Loss of material due to abrasion; cavitation 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.T-20 

M 057 BWR/PWR Constant and variable 

load spring hangers; guides; stops 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.T-28 

III.B1.2.T-28 III.B1.3.T-28 

E 058 BWR/PWR Earthen water-control 

structures: dams; embankments; reservoirs; channels; canals and ponds 

Loss of material; loss of form due to erosion, settlement, sedimentation, frost action, waves, currents, surface runoff, seepage 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.T-22 
3.5-32 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 059 BWR/PWR Group 6: concrete 

(accessible areas): all 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-38 

E 060 BWR/PWR Group 6: concrete 

(accessible areas): exterior above- and below-grade; foundation 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-36 

E 061 BWR/PWR Group 6: concrete 

(accessible areas): exterior above- and below-grade; foundation; interior slab 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-37 
3.5-33 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 062 BWR/PWR Group 6: Wooden Piles; 

sheeting 

Loss of material; change in material properties due to weathering, chemical degradation, and insect infestation repeated wetting and drying, fungal decay 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-223 

 063 BWR/PWR Groups 1-3, 5, 7-9: 

concrete (accessible areas): exterior aboveand below-grade; foundation 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-24 

III.A2.TP-24 III.A3.TP-24 III.A5.TP-24 III.A7.TP-24 III.A8.TP-24 III.A9.TP-24 

 064 BWR/PWR Groups 1-3, 5, 7-9: 

concrete (accessible areas): exterior aboveand below-grade; foundation 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-23 

III.A2.TP-23 III.A3.TP-23 III.A5.TP-23 III.A7.TP-23 III.A8.TP-23 III.A9.TP-23 
3.5-34 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 065 BWR/PWR 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 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-212 

III.A1.TP-27 III.A2.TP-212 III.A2.TP-27 III.A3.TP-212 III.A3.TP-27 III.A5.TP-212 III.A5.TP-27 III.A6.TP-104 III.A7.TP-212 III.A7.TP-27 III.A8.TP-212 III.A8.TP-27 III.A9.TP-212 III.A9.TP-27 

 066 BWR/PWR Groups 1-5, 7, 9: 

concrete (accessible areas): interior and above-grade exterior 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-26 

III.A2.TP-26 III.A3.TP-26 III.A4.TP-26 III.A5.TP-26 III.A7.TP-26 III.A9.TP-26 

 067 BWR/PWR 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 

Increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to aggressive chemical attack 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-28 

III.A1.TP-29 III.A2.TP-28 III.A2.TP-29 III.A3.TP-28 III.A3.TP-29 III.A4.TP-28 III.A5.TP-28 III.A5.TP-29 III.A6.TP-107 III.A7.TP-28 III.A7.TP-29 III.A8.TP-29 III.A9.TP-28 III.A9.TP-29 
3.5-35 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 068 BWR/PWR High-strength steel 

structural bolting 

Cracking due to SCC AMP XI.S3, 

"ASME Section XI, Subsection IWF" 

No III.B1.1.TP-41 

D 069  070 BWR/PWR Masonry walls: all Cracking due to restraint 

shrinkage, creep, aggressive environment 

AMP XI.S5, "Masonry Walls" 

No III.A1.T-12 

III.A2.T-12 III.A3.T-12 III.A5.T-12 III.A6.T-12 

M 071 BWR/PWR Masonry walls: all Loss of material (spalling, 

scaling) and cracking due to freeze-thaw 

AMP XI.S5, "Masonry Walls" 

No III.A1.TP-34 

III.A2.TP-34 III.A3.TP-34 III.A5.TP-34 III.A6.TP-34 

M 072 BWR/PWR Seals; gasket; moisture 

barriers (caulking, flashing, and other sealants) 

Loss of sealing due to wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S6, "Structures Monitoring" 

No III.A6.TP-7 

 073 BWR/PWR Service Level I coatings Loss of coating or lining 

integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage 

AMP XI.S8, "Protective Coating Monitoring and Maintenance" 

No III.A4.TP-301 

M 074 BWR/PWR Sliding support bearings; 

sliding support surfaces 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-46 

III.B2.TP-47 III.B4.TP-46 III.B4.TP-47 

M 075 BWR/PWR Sliding surfaces Loss of mechanical 

function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-45 

III.B1.2.TP-45 III.B1.3.TP-45 

M 076 BWR/PWR Sliding surfaces: radial 

beam seats in BWR drywell 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S6, "Structures Monitoring" 

No III.A4.TP-35 
3.5-36 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 077 BWR/PWR Steel components: all 

structural steel 

Loss of material due to corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-302 

III.A2.TP-302 III.A3.TP-302 III.A4.TP-302 III.A5.TP-302 III.A7.TP-302 III.A8.TP-302 

M 078 BWR/PWR Stainless steel fuel pool 

liner 

Cracking due to SCC; Loss of material due to pitting and crevice corrosion 

AMP XI.M2, "Water Chemistry," and monitoring of the spent fuel pool water level and leakage from the leak chase channels. 

No III.A5.T-14 

 079 BWR/PWR Steel components: piles Loss of material due to 

corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A3.TP-219 

 080 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-248 

III.A2.TP-248 III.A3.TP-248 III.A4.TP-248 III.A5.TP-248 III.A6.TP-248 III.A7.TP-248 III.A8.TP-248 III.A9.TP-248 III.B2.TP-248 III.B3.TP-248 III.B4.TP-248 III.B5.TP-248 

 081 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-226

III.B1.2.TP-226III.B1.3.TP-226 
3.5-37 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 082 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-274 

III.A2.TP-274 III.A3.TP-274 III.A4.TP-274 III.A5.TP-274 III.A7.TP-274 III.A8.TP-274 III.A9.TP-274 III.B2.TP-274 III.B3.TP-274 III.B4.TP-274 III.B5.TP-274 

E 083 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-221 

D 084 M 085 BWR/PWR Structural bolting Loss of material due to 

pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-232

III.B1.2.TP-232III.B1.3.TP-232 

 086 BWR/PWR Structural bolting Loss of material due to 

pitting, crevice corrosion 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-235

III.B1.2.TP-235III.B1.3.TP-235 

 087 BWR/PWR Structural bolting Loss of preload due to 

self-loosening 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-229

III.B1.2.TP-229III.B1.3.TP-229 
3.5-38 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 088 BWR/PWR Structural bolting Loss of preload due to 

self-loosening 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-261 

III.A2.TP-261 III.A3.TP-261 III.A4.TP-261 III.A5.TP-261 III.A6.TP-261 III.A7.TP-261 III.A8.TP-261 III.A9.TP-261 III.B2.TP-261 III.B3.TP-261 III.B4.TP-261 III.B5.TP-261 

 089 PWR Support members; welds; 

bolted connections; support anchorage to building structure 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No III.B1.1.T-25 

III.B1.1.TP-3 III.B1.2.T-25 III.B1.3.TP-3 III.B1.2.TP-3 III.B2.T-25 III.B2.TP-3 III.B3.T-25 III.B3.TP-3 III.B4.T-25 III.B4.TP-3 III.B5.T-25 III.B5.TP-3 

E 090 BWR/PWR Support members; welds; 

bolted connections; support anchorage to building structure 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-10 

 091 BWR/PWR Support members; welds; 

bolted connections; support anchorage to building structure 

Loss of material due to general, pitting corrosion 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.T-24 

III.B1.2.T-24 III.B1.3.T-24 
3.5-39 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

 092 BWR/PWR Support members; welds; 

bolted connections; support anchorage to building structure 

Loss of material due to general, pitting corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-43 

III.B3.TP-43 III.B4.TP-43 III.B5.TP-43 

M 093 BWR/PWR Galvanized steel support 

members; welds; bolted connections; support anchorage to building structure 

Loss of material due to pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-6 

III.B4.TP-6 

M 094 BWR/PWR Vibration isolation 

elements 

Reduction or loss of isolation function due to radiation hardening, temperature, humidity, sustained vibratory loading 

AMP XI.S3, "ASME Section XI, Subsection IWF," and/or AMP XI.S6, "Structures Monitoring" 

No III.B1.1.T-33 

III.B1.2.T-33 III.B1.3.T-33 III.B4.TP-44 

E 095 BWR/PWR Galvanized steel support 

members; welds; bolted connections; support anchorage to building structure 

None None No III.B1.1.TP-8 

III.B1.2.TP-8 III.B1.3.TP-8 III.B2.TP-8 III.B3.TP-8 III.B4.TP-8 III.B5.TP-8 

N 096 BWR/PWR Groups 6: concrete 

(accessible areas): all 

Cracking due to expansion from reaction with aggregates 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" 

No III.A6.T-34 

N 097 BWR/PWR Group 4: Concrete 

(reactor cavity area proximate to the reactor vessel): reactor (primary/biological) shield wall; sacrificial shield wall; reactor vessel support/pedestal structure 

Reduction of strength; loss of mechanical properties due to irradiation (i.e., radiation interactions with material and radiation-induced heating) 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.6) 

III.A4.T-35 
3.5-40 

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports 

Evaluated in Chapters II and III of the GALL-SLR Report 

New, 

Modified, 

Deleted, 

Edited Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 098 BWR/PWR Stainless steel, aluminum 

alloy support members; welds; bolted connections; support anchorage to building structure 

None None No III.B1.1.TP-4 

III.B1.2.TP-4 III.B1.3.TP-4 III.B2.TP-4 III.B3.TP-4 III.B4.TP-4 III.B5.TP-4 

N 099 BWR/PWR Aluminum, stainless steel 

support members; welds; bolted connections; support anchorage to building structure 

Loss of material due to pitting and crevice corrosion, cracking due to SCC 

AMP XI.M32, "One-Time Inspection," AMP XI.S3, "ASME Section XI, Subsection IWF," or AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.5.2.2.2.4) 

III.B1.1.T-36a III.B1.1.T-36b III.B1.1.T-36c III.B1.2.T-36a III.B1.2.T-36b III.B1.2.T-36c III.B1.3.T-36a III.B1.3.T-36b III.B1.3.T-36c 

N 100 BWR/PWR Aluminum, stainless steel 

support members; welds; bolted connections; support anchorage to building structure 

Loss of material due to pitting and crevice corrosion, cracking due to SCC 

AMP XI.M32, "One-Time Inspection," AMP XI.S6, "Structures Monitoring," or AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.5.2.2.2.4) 

III.B2.T-37a III.B2.T-37b III.B2.T-37c III.B3.T-37a III.B3.T-37b III.B3.T-37c III.B4.T-37a III.B4.T-37b III.B4.T-37c III.B5.T-37a III.B5.T-37b III.B5.T-37c 
3.5-41 

Table 3.5-2 AMPs and Additional Guidance Appendices Recommended for 

Containments, Structures, and Component Supports 

GALL-SLR Report Chapter/AMP Program Name 

AMP XI.M2 Water Chemistry 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M32 One-Time Inspection 

AMP XI.M36 External Surfaces Monitoring of Mechanical 

Components 

AMP XI.S1 ASME Section XI, Subsection IWE 

AMP XI.S2 ASME Section XI, Subsection IWL 

AMP XI.S3 ASME Section XI, Subsection IWF 

AMP XI.S4 10 CFR Part 50, Appendix J 

AMP XI.S5 Masonry Walls 

AMP XI.S6 Structures Monitoring 

AMP XI.S7 Inspection of Water-Control Structures Associated with 

Nuclear Power Plants 

AMP XI.S8 Protective Coating Monitoring and Maintenance 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic 

(Branch Technical Position RLSB-1) 

3.6-1

3.6 Aging Management of Electrical and Instrumentation and Controls 

Review Responsibilities 

Primary— The branch(es) assigned responsibility by the Project Manager for the safety review of 

the subsequent license renewal application. 

Secondary—None 

3.6.1 Areas of Review 

This section addresses the aging management review (AMR) and the associated aging 

management programs (AMPs) of the electrical and instrumentation and control (I&C). For a 

recent vintage plant, the information related to the electrical and I&C is contained in Chapter 7, 

“Instrumentation and Controls,” and Chapter 8, “Electric Power,” of the plant’s Final Safety 

Analysis Report (FSAR), consistent with the “Standard Review Plan for the Review of Safety 

Analysis Reports for Nuclear Power Plants” (NUREG–0800) (Ref. 1). For older plants, the 

location of applicable information is plant-specific because an older plant’s FSAR may have 

predated NUREG–0800. Typical electrical and I&C components that are subject to an AMR for 

subsequent license renewal (SLR) are electrical cables and connections, metal enclosed buses, 

cable bus, fuse holders, high-voltage insulators, transmission conductors and connections, and 

switchyard bus and connections. 

The responsible review organization is to review the following subsequent license renewal 

application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 1.2: 

AMRs 

 AMR results consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report 

 AMR results for which further evaluation is recommended 

 AMR results not consistent with or not addressed in the GALL-SLR Report 

AMPs 

 Consistent with GALL-SLR Report AMPs 

 Plant-specific AMPs 

FSAR Supplement 

 The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP. 

3.6.2 Acceptance Criteria 

The acceptance criteria for the areas of review describe methods for determining whether the 

applicant has met the requirements of the U.S. Nuclear Regulatory Commissions (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21.
3.6-2

3.6.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The AMRs and the AMPs applicable to the electrical and I&C components are described and 

evaluated in Chapter VI of the GALL-SLR Report. 

The applicant’s SLRA should provide sufficient information for the NRC reviewer to confirm that 

the specific SLRA AMR item and the associated SLRA AMP are consistent with the cited 

GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

consistent with the GALL-SLR Report AMR item to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

capable of managing the effects of aging as adequately as the AMP recommended by the 

GALL-SLR Report. 

3.6.2.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic acceptance criteria defined in Section 3.6.2.1 need to be applied first for all of the 

AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR item 

to which the SLRA AMR item is compared identifies that “further evaluation is recommended,” 

then additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.6-1, comparing the “Further Evaluation 

Recommended” and the “GALL-SLR Item” column, for the AMR items that reference the 

following subsections. 

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

Environmental qualification is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The evaluation of 

this TLAA is addressed separately in Section 4.4, “Environmental Qualification (EQ) of Electrical 

Equipment,” of this SRP-SLR. 

3.6.2.2.2 Reduced Insulation Resistance Due to Age Degradation of Cable Bus 

Arrangements Caused by Intrusion of Moisture, Dust, Industrial Pollution, Rain, 

Ice, Photolysis, Ohmic Heating and Loss of Strength of Support Structures and 

Louvers of Cable Bus Arrangements Due to General Corrosion and Exposure to 

Air Outdoor 

Reduced insulation resistance due to age degradation of cable bus caused by intrusion of 

moisture, dust, industrial pollution, rain, ice, photolysis (for ultraviolet sensitive material only), 

ohmic heating and loss of strength of support structures, covers or louvers of cable bus 

arrangements due to general corrosion or exposure to air outdoor could occur in cable bus 

assemblies. Cable bus is a variation of metal enclosed bus (MEB) which is similar in construction 

to an MEB, but instead of segregated or nonsegregated electrical buses, cable bus is comprised 

of a fully enclosed metal enclosure that utilizes three-phase insulated power cables installed on 

insulated support blocks. Cable bus may omit the top cover or use a louvered top cover and 

enclosure. Both the cable bus and enclosures are not sealed against intrusion of dust, industrial 

pollution, moisture, rain, and ice and therefore may introduce debris into the internal cable 

bus assembly. 
3.6-3

Consequently, cable bus construction and arrangements are such that it may not readily fall under 

a specific GALL-SLR Report AMP (e.g., GALL-SLR Report AMP XI.E1 and AMP XI.E4). 

GALL-SLR Report AMP XI.E1 calls for a visual inspection of accessible insulated cables and 

connections subject to an adverse localized environment which may not be applicable to cable 

bus due to inaccessibility or applicability of the aging mechanisms and effects. GALL-SLR Report 

AMP XI.E4 includes tests and inspections of the internal and external portions of the MEB. The 

MEB internal and external inspections and tests may not be applicable to cable bus aging 

mechanisms and effects. Therefore, the GALL-SLR Report recommends cable bus aging 

mechanisms and effects be evaluated as a plant-specific further evaluation. The evaluation 

includes associated AMPs: AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components,” and AMP XI.S6, “Structures Monitoring.” Acceptance criteria are 

described in Branch Technical Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR). 

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 

Preload for Transmission Conductors, Switchyard Bus, and Connections 

Loss of material due to wind-induced abrasion, loss of conductor strength due to corrosion, and 

increased resistance of connection due to oxidation or loss of preload could occur in transmission 

conductors and connections, and in switchyard bus and connections. The GALL-SLR Report 

recommends further evaluation of a plant-specific AMP to demonstrate that this aging effect is 

adequately managed. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this 

SRP-SLR). 

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR). 

3.6.2.2.5 Ongoing Review of Operating Experience 

Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

Management Programs.” 

3.6.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.6.2.4 Aging Management Programs 

For those AMPs that will be used for aging management and that are based on the program 

elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

credited in the SLRA to confirm consistency with the GALL-SLR Report AMPs identified in 

Chapters X and XI. 

If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

AMP, with all exceptions, would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, the 
3.6-4

difference should be reviewed and properly dispositioned. The reviewer should document the 

disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

The SLRA should identify any enhancements that are needed to permit an existing AMP to be 

declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. The 

reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

plant AMP to be consistent with the GALL-SLR Report AMP and also that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the subsequent 

period of extended operation. The reviewer should review and document the disposition of 

all enhancements. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 

3.6.2.5 Final Safety Analysis Report Supplement 

The summary description of the programs and activities for managing the effects of aging for the 

subsequent period of extended operation in the FSAR Supplement should be sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

should contain information associated with the bases for determining that aging effects are 

managed during the subsequent period of extended operation. The description should also 

contain any future aging management activities, including commitments, license conditions, 

enhancements, and exceptions, to be implemented prior to or during the subsequent period of 

extended operation. Table X-01 and Table XI-01 of the GALL-SLR Report provide examples of 

the type of information to be included in the FSAR Supplement. Table 3.6-2 lists the programs 

that are applicable for this SRP-SLR subsection. 

3.6.3 Review Procedures 

For each area of review, the following review procedures are to be followed: 

3.6.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

Learned for Subsequent License Renewal Report 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and demonstrate 

that the AMRs and AMPs at its facility are consistent with those reviewed and approved in the 

GALL-SLR Report. The reviewer should not conduct a re-review of the substance of the matters 

described in the GALL-SLR Report. If the applicant has provided the information necessary to 

adopt the finding of program acceptability as described and evaluated in the GALL-SLR Report, 

the reviewer should find acceptable the applicant’s reference to the GALL-SLR Report in its 

SLRA. In making this determination, the reviewer confirms that the applicant has provided a brief 

description of the system, components, materials, and environment. The reviewer also confirms 

that the applicable aging effects, have been addressed based on the staff’s review of industry and 

plant-specific operating experience (OE). 

Furthermore, the reviewer should confirm that the applicant has addressed OE identified after the 

issuance of the GALL-SLR Report. Performance of this review includes confirming that the 

applicant has identified those aging effects for the electrical and I&C components that are 

contained in the GALL-SLR Report as applicable to its plant. 
3.6-5

3.6.3.2 Aging Management Review Results for Which Further Evaluation Is Recommended by 

the Generic Aging Lessons Learned for Subsequent License Renewal Report 

The basic review procedures defined in Section 3.6.3.1 need to be applied first for all of the AMRs 

and AMPs provided in this section. In addition, if the GALL-SLR AMR item to which the SLRA 

AMR item is compared identifies that “further evaluation is recommended,” then additional criteria 

apply as identified by the GALL-SLR Report for each of the following aging effect/aging 

mechanism combinations. 

3.6.3.2.1 Electrical Equipment Subject to Environmental Qualification 

Environmental qualification is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews the evaluation of this 

TLAA separately following the guidance in Section 4.4 of this SRP-SLR. 

3.6.3.2.2 Reduced Insulation Resistance Due to Age Degradation of Cable Bus 

Arrangements Caused by Intrusion of Moisture, Dust, Industrial Pollution, Rain, 

Ice, Photolysis, Ohmic Heating and Loss of Strength of Support Structures and 

Louvers of Cable Bus Arrangements Due to General Corrosion and Exposure to 

Air Outdoor 

The GALL-SLR Report recommends a plant-specific Cable Bus AMP for the management of 

reduced insulation resistance due to age degradation of cable bus caused by intrusion of 

moisture, dust, industrial pollution, rain, ice, photolysis (for ultraviolet sensitive material only), 

ohmic heating and loss of strength of support structures, covers or louvers of cable bus 

arrangements due to general corrosion or exposure to air outdoor. The reviewer reviews the 

applicant’s proposed program on a case-by-case basis to verify that an adequate program will be 

in place for the management of these aging effects. 

3.6.3.2.3 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 

Preload for Transmission Conductors, Switchyard Bus, and Connections 

The GALL-SLR Report recommends a plant-specific AMP for the management of loss of material 

due to wind-induced abrasion, loss of conductor strength due to corrosion, and increased 

resistance of connection due to oxidation or loss of preload in transmission conductors and 

connections, and in switchyard bus and connections. The reviewer reviews the applicant’s 

proposed program on a case-by-case basis to verify that an adequate program will be in place for 

the management of these aging effects. 

3.6.3.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

The applicant’s AMPs for SLR should contain the elements of corrective actions, the confirmation 

process, and administrative controls. Safety-related components are covered by 10 CFR Part 50, 

Appendix B, which is adequate to address these program elements. However, Appendix B does 

not apply to nonsafety-related components that are subject to an AMR for SLR. Nevertheless, the 

applicant has the option to expand the scope of its 10 CFR Part 50, Appendix B program to 

include these components and address these program elements. If the applicant chooses this 

option, the reviewer confirms that the applicant has documented such a commitment in the FSAR 

Supplement. If the applicant chooses alternative means, the branch responsible for quality 

assurance should be requested to review the applicant’s proposal on a case-by-case basis. 
3.6-6

3.6.3.2.5 Ongoing Review of Operating Experience 

The applicant’s AMPs should contain the element of OE. The reviewer verifies that the applicant 

has appropriate programs or processes for the ongoing review of both plant-specific and industry 

OE concerning age-related degradation and aging management. Such reviews are used to verify 

that the AMPs are effective to manage the aging effects for which they are created. The AMPs 

are either enhanced or new AMPs are developed, as appropriate, when it is determined through 

the evaluation of OE that the effects of aging may not be adequately managed. Additional 

information is in Appendix A.4, “Operating Experience for Aging Management Programs” of this 

SRP-SLR. In addition, the reviewer confirms that the applicant has provided an appropriate 

summary description of these activities in the FSAR Supplement. 

3.6.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

Generic Aging Lessons Learned for Subsequent License Renewal Report 

The reviewer should confirm that the applicant, in the SLRA, has identified applicable aging 

effects, listed the appropriate combination of materials and environments, and has credited AMPs 

that will adequately manage the aging effects. The AMP credited by the applicant could be an 

AMP that is described and evaluated in the GALL-SLR Report or in a plant-specific program. 

Review procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

3.6.3.4 Aging Management Programs 

The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not 

identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which the 

SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this difference 

satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

pertinent to the electrical and I&C components are summarized in Table 3.6-1 of this SRP-SLR. 

The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR Report, 

Chapters VI, presenting detailed information summarized by this row. 

If the applicant chooses to use a plant-specific program that is not a GALL-SLR Report AMP, the 

NRC reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

(Appendix A.1 of this SRP-SLR). 

3.6.3.5 Final Safety Analysis Report Supplement 

The reviewer confirms that the applicant has provided in its FSAR Supplement information for 

aging management of the Electrical and I&C System. Table 3.6-2 lists the AMPs that are 

applicable for this SRP-SLR subsection. The reviewer also confirms that the applicant has 

provided information for Subsection 3.6.3.3, “Aging Management Review Results Not Consistent 

With or Not Addressed in the Generic Aging Lessons Learned for Subsequent License 

Renewal Report.” 
3.6-7

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date.

3.6.4 Evaluation Findings 

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of this section, then an evaluation finding similar to the following text should be included 

in the NRC staff’s safety evaluation report: 

On the basis of its review the NRC staff concludes that the applicant has demonstrated 

that the aging effects associated with the electrical and I&C components will be 

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

the current licensing basis for the subsequent period of extended operation, as required 

by 10 CFR 54.21(a)(3). 

The NRC staff also reviewed the applicable FSAR Supplement program summary 

descriptions and concludes that they adequately describe the AMPs credited for 

managing aging of electrical and I&C, as required by 10 CFR 54.21(d). 

3.6.5 Implementation 

Except for cases in which the applicant proposes an alternative method for complying with 

specified portions of NRC regulations, NRC staff members follow the methods described herein in 

their evaluation of conformance with NRC regulations. The staff evaluates these alternatives and 

finds them acceptable if the staff determines that the alternatives provide reasonable assurance 

that the component’s intended functions will be maintained. 

3.6.6 References 

1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML070630046. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 2007.
3.6-8

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 001 BWR/PWR Electrical equipment 

subject to 10 CFR 50.49 EQ requirements composed of various polymeric and metallic materials in plant areas subject to a harsh environment (i.e., loss of coolant accident (LOCA), high energy line break (HELB), or post LOCA environment or, An adverse localized environment for the most limiting qualified condition for temperature, radiation, or moisture for the component material (e.g., cable or connection insulation). 

Various aging effects due to various mechanisms in accordance with 10 CFR 50.49 

EQ is a time-limited aging analysis (TLAA) to be evaluated for the subsequent period of extended operation. See the Standard Review Plan, Section 4.4, "Environmental Qualification (EQ) of Electric Equipment," for acceptable methods for meeting the requirements of 10 CFR 54.21(c)(1)(i) and (ii). See AMP X.E1, "Environmental Qualification (EQ) of Electric Equipment," of this report for meeting the requirements of 10 CFR 54.21(c)(1)(i)-(iii). 

Yes, TLAA (SRP-SLR Section 3.6.2.2.1) 

VI.B.L-05 

M 002 BWR/PWR High-voltage 

electrical insulators composed of porcelain; malleable iron; aluminum; galvanized steel; cement exposed to air – outdoor 

Loss of material due to mechanical wear or corrosion caused by movement of transmission conductors due to significant wind 

AMP XI.E7, "High-Voltage Insulators" 

No VI.A.LP-32 
3.6-9

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 003 BWR/PWR High-voltage 

electrical insulators composed of porcelain; malleable iron; aluminum; galvanized steel; cement exposed to air – outdoor 

Reduced electrical insulation resistance due to presence of cracks, foreign debris, salt, dust, cooling tower plume or industrial effluent contamination 

AMP XI.E7, "High-Voltage Insulators" 

No VI.A.LP-28 

E 004 BWR/PWR Transmission 

conductors composed of aluminum; steel exposed to air – outdoor 

Loss of conductor strength due to corrosion 

A plant-specific aging management program is to be evaluated for ACSR 

Yes (SRP-SLR Section 3.6.2.2.3) 

VI.A.LP-38 

E 005 BWR/PWR Transmission 

connectors composed of aluminum; steel exposed to air – outdoor 

Increased electrical resistance of connection due to oxidation or loss of preload 

A plant-specific aging management program is to be evaluated 

Yes (SRP-SLR Section 3.6.2.2.3) 

VI.A.LP-48 

E 006 BWR/PWR Switchyard bus and 

connections composed of aluminum; copper; bronze; stainless steel; galvanized steel exposed to air – outdoor 

Loss of material due to windinduced abrasion; Increased electrical resistance of connection due to oxidation or loss of pre-load 

A plant-specific aging management program is to be evaluated 

Yes (SRP-SLR Section 3.6.2.2.3) 

VI.A.LP-39 

E 007 BWR/PWR Transmission 

conductors composed of aluminum; steel exposed to air – outdoor 

Loss of material due to windinduced abrasion A plant-specific aging management program is to 

be evaluated for All Aluminum Conductor (AAC), ACAR and ACSR 

Yes (SRP-SLR Section 3.6.2.2.3) 

VI.A.LP-47 
3.6-10

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 008 BWR/PWR Electrical insulation 

for electrical cables and connections (including terminal blocks, etc.) composed of various organic polymers (e.g., EPR, SR, EPDM, XLPE) exposed to an adverse localized environment caused by heat, radiation, or moisture 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis (UV sensitive materials only) of organics; radiation-induced oxidation; moisture intrusion 

AMP XI.E1, "Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-33 

E 009 BWR/PWR Electrical insulation 

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 an adverse localized environment caused by heat, radiation, or moisture 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis (UV sensitive materials only) of organics; radiation-induced oxidation; moisture intrusion 

AMP XI.E2, "Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits" 

No VI.A.LP-34 
3.6-11

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 010 BWR/PWR Electrical conductor 

insulation for inaccessible power, instrumentation, and control cables (e.g., installed in duct bank, buried conduit or direct buried) composed of various organic polymers such as EPR, SR, EPDM, XLPE, butyl rubber, and combined thermoplastic jacket/insulation shield exposed to an adverse localized environment caused by significant moisture 

Reduced electrical insulation resistance or degraded dielectric strength due to significant moisture 

AMP XI.E3A, "Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements," AMP XI.E3B, "Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements," or AMP XI.E3C, "Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-35a

VI.A.LP-35bVI.A.LP-35c 

 011 BWR/PWR Metal enclosed bus: 

enclosure assemblies composed of elastomers exposed to air – indoor controlled or uncontrolled, air – outdoor 

Surface cracking, crazing, scuffing, dimensional change (e.g. "ballooning" and "necking"), shrinkage, discoloration, hardening or loss of strength due to elastomer degradation 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VI.A.LP-29 
3.6-12

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 012 BWR/PWR Metal enclosed bus: 

bus/connections composed of various metals used for electrical bus and connections exposed to air – indoor controlled or uncontrolled, air – outdoor 

Increased electrical resistance of connection due to the loosening of bolts caused by thermal cycling and ohmic heating 

AMP XI.E4, "Metal Enclosed Bus" 

No VI.A.LP-25 

E 013 BWR/PWR Metal enclosed bus: 

electrical insulation; insulators composed of porcelain; xenoy; thermo-plastic organic polymers exposed to air – indoor controlled or uncontrolled, air – outdoor 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics/thermoplastics , radiation-induced oxidation, moisture/debris intrusion, and ohmic heating 

AMP XI.E4, "Metal Enclosed Bus" 

No VI.A.LP-26 

 014 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies composed of steel exposed to air – indoor uncontrolled, air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.S6, "Structures Monitoring" 

No VI.A.LP-43 

 015 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies composed of galvanized steel; aluminum exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.S6, "Structures Monitoring" 

No VI.A.LP-42 
3.6-13

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

M 016 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to air – indoor uncontrolled 

Increased electrical resistance of connection due to chemical contamination, corrosion, and oxidation (in an air, indoor controlled environment, increased resistance of connection due to chemical contamination, corrosion and oxidation do not apply) 

AMP 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 and effects due to chemical contamination, corrosion, and oxidation. 

No VI.A.LP-23 

N 017 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to airindoor controlled or uncontrolled 

Increased electrical resistance of connection due to fatigue from ohmic heating, thermal cycling, electrical transients 

AMP XI.E5, "Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are not subject to fatigue due to ohmic heating, thermal cycling, electrical transients. 

No VI.A.L-07 

M 018 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to air – indoor controlled or uncontrolled 

Increased electrical resistance of connection due to fatigue caused by frequent fuse removal/manipulation or vibration 

AMP XI.E5, "Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are not subject to fatigue caused by frequent fuse removal/manipulation or vibration. 

No VI.A.LP-31 
3.6-14

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

E 019 BWR/PWR Cable connections 

(metallic parts) composed of various metals used for electrical contacts exposed to air – indoor controlled or uncontrolled, air – outdoor 

Increased electrical resistance of connection due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation 

AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-30 

E 020 PWR Electrical connector 

contacts for electrical connectors composed of various metals used for electrical contacts exposed to air with borated water leakage 

Increased electrical resistance of connection due to corrosion of connector contact surfaces caused by intrusion of borated water 

AMP XI.M10, "Boric Acid Corrosion" 

No VI.A.LP-36 

M 021 BWR/PWR Transmission 

conductors composed of aluminum exposed to air – outdoor 

Loss of conductor strength due to corrosion 

None - for ACAR and All Aluminum Conductor (AAC) 

No VI.A.LP-46 

M 022 BWR/PWR Fuse holders (not 

part of active equipment): insulation material composed of electrical insulation material: bakelite; phenolic melamine or ceramic; molded polycarbonate, and other, exposed to air – indoor controlled or uncontrolled 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis (UV sensitive materials only) of organics; radiation-induced oxidation; moisture intrusion 

AMP 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 

No VI.A.LP-24 
3.6-15

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 023 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies. Galvanized steel; aluminum. air – indoor controlled or uncontrolled 

None None No VI.A.LP-41 

N 024 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies. Steel air – indoor controlled 

None None No VI.A.LP-44 

D 026 N 027 BWR/PWR Cable bus: external 

surface of enclosure assemblies galvanized steel; aluminum; air – indoor controlled or uncontrolled 

None None No VI.A.L-09 

D 028 N 029 BWR/PWR Cable bus: electrical 

insulation; insulators – exposed to air – indoor controlled or uncontrolled, air – outdoor 

Reduced electrical insulation resistance due to degradation caused thermal/thermoxidative degradation of organics and photolysis (UV sensitive materials only) of organics, moisture/debris intrusion and ohmic heating 

A plant-specific aging management program is to be evaluated 

Yes (SRP-SLR Section 3.6.2.2.2) 

VI.A.L-11 

N 030 BWR/PWR Cable bus: external 

surface of enclosure assemblies composed of steel exposed to air – indoor uncontrolled or air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

A plant-specific aging management program is to be evaluated 

Yes (SRP-SLR Section 3.6.2.2.2) 

VI.A.L-12 
3.6-16

Table 3.6-1 Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL-SLR Report

New, 

Modified, 

Deleted, 

Edited Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further Evaluation 

Recommended 

GALL-SLR 

Item 

N 031 BWR/PWR Cable bus external 

surface of enclosure assemblies composed of galvanized steel; aluminum exposed to air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

A plant-specific aging management program is to be evaluated 

Yes (SRP-SLR Section 3.6.2.2.2) 

VI.A.L-13 

N 032 BWR/PWR Cable bus: external 

surface of enclosure assemblies: composed of steel; air – indoor controlled 

None None No VI.A.L-14 
3.6-17

Table 3.6-2 AMPs and Additional Guidance Appendices Recommended for 

Electrical and Instrumentation and Control Systems 

GALL-SLR Report Chapter/AMP Program Name 

AMP X.E1 Environmental Qualification of Electric Equipment 

AMP XI.E1 Electrical Insulation for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

AMP XI.E2 Electrical Insulation for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation 

Circuits 

AMP XI.E3A Electrical Insulation for Inaccessible Medium-Voltage 

Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements 

AMP XI.E3B Electrical Insulation for Inaccessible Instrument and 

Control Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements 

AMP XI.E3C Electrical Insulation for Inaccessible Low-Voltage Power 

Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

AMP XI.E4 Metal Enclosed Bus 

AMP XI.E5 Fuse Holders 

AMP XI.E6 Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

AMP XI.E7 High-Voltage Insulators 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components 

AMP XI.S6 Structures Monitoring 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLBS-1) 

4.1-1 

4 TIME-LIMITED AGING ANALYSES 

4.1 Identification of Time-Limited Aging Analyses and Exemptions 

Review Responsibilities 

Primary—Branch(es) responsible for the time-limited aging analysis (TLAA) issues 

Secondary—Other branches responsible for engineering, as appropriate 

4.1.1 Areas of Review 

This review plan section addresses the identification of TLAAs. The technical review of TLAAs is 

addressed in Sections 4.2 through 4.7. As explained in more detail below, the list of TLAAs are 

certain plant-specific safety analyses that are defined, in part, by the current operating term. 

Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1), a license renewal 

applicant is required to provide a list of TLAAs, as defined in 10 CFR 54.3. The area relating to 

the identification of TLAAs is reviewed. 

TLAAs may have developed since issuance of a plant’s operating license. As indicated in 

10 CFR 54.30, the adequacy of the plant’s current licensing basis (CLB), which includes TLAAs, is 

not an area within the scope of the subsequent license renewal review. Any questions regarding 

the adequacy of the CLB are addressed under the backfit rule (10 CFR 50.109) and are separate 

from the license renewal process. 

In addition, pursuant to 10 CFR 54.21(c)(2), an applicant must provide a list of plant-specific 

exemptions granted under 10 CFR 50.12 that are based on TLAAs. The U.S. Nuclear Regulatory 

Commission (NRC) staff should focus its review to confirm that the applicant did not omit any 

TLAAs, as defined in 10 CFR 54.3. 

Pursuant to 10 CFR 54.21(d), each application includes a final safety analysis report (FSAR), 

updated final safety analysis report, or updated safety analysis report, as appropriate for the CLB 

supplement summary description for each TLAA that is identified in accordance with 

10 CFR 54.21(c)(1). 

4.1.2 Acceptance Criteria 

The acceptance criteria for the areas of review described in Subsection 4.1.1 of this review 

plan section delineate acceptable methods for meeting the requirements of the NRC’s regulations 

in 10 CFR 54.21(c)(1). For the applicant’s list of exemptions to be acceptable under the 

requirement in 10 CFR 54.21(c)(2), the NRC staff should have reasonable assurance that there 

has been no omission of TLAAs from the subsequent license renewal application (SLRA) that 

were used as the basis for receiving NRC approval of regulatory exemptions granted in 

accordance with 10 CFR 50.12 requirements. 

TLAAs are those licensee calculations and analyses that meet all six of the following criteria, as 

defined in 10 CFR 54.3(a): 

1. Involve systems, structures, and components within the scope of license renewal, as 

delineated in 10 CFR 54.4(a); 
4.1-2 

2. Consider the effects of aging; 

3. Involve time-limited assumptions defined by the current operating term, for example, 

40 years; 

4. Were determined to be relevant by the licensee in making a safety determination; 

5. Involve conclusions or provide the basis for conclusions related to the capability of the 

system, structure, or component to perform its intended function(s), as delineated in 

10 CFR 54.4(b); and 

6. Are contained or incorporated by reference in the CLB. 

The TLAA identification criterion in Criterion 1 is based only on a comparison to the scoping 

requirements in 10 CFR 54.4 and therefore does not limit the applicability of TLAAs only to those 

components that would be required to be screened in for an aging management review in 

accordance with the requirement in 10 CFR 54.21(a)(1). Thus, the possibility exists that, for a 

given CLB, a TLAA may need to be identified for a given active component if the analysis in the 

CLB is determined to be in conformance with all six of the criteria in 10 CFR 54.3(a) for identifying 

an analysis as a TLAA. Fatigue flaw growth analyses of pressurized water reactor coolant pump 

flywheels are examples of plant-specific analyses that apply to an active component type and may 

need to be identified as a TLAA for a given application. 

The applicant’s FSAR (as updated) identifies TLAAs that were incorporated by reference into the 

CLB. In addition, for subsequent license renewal (SLR) applications, there may be situations 

where an analysis of record was not required to be identified as a TLAA for the current operating 

period (as approved in the renewed operating license for the facility), but will need to be identified 

as a TLAA for a proposed subsequent period of extended operation, as required by the regulation 

in 10 CFR 54.21(c)(1). Specifically, criterion 3 for TLAAs in 10 CFR 54.3(a) establishes that to be 

a TLAA the analysis has to involve time-limited assumptions defined by the current operating 

term. In Federal Register Notice (FRN) No. 95-11136, Volume 60, Number 88, dated 

May 8, 1995 (Ref. 1), the NRC identified that TLAAs are those: 

analyses with (i) time-related assumptions, (ii) utilized in determining the acceptability of 

SSCs, within the scope of license renewal (as defined in 10 CFR 54.4), (iii) which are 

based upon a period of plant operation equal to or greater than the current license 

term, but less than the cumulative period of plant operation (viz., the existing license 

term plus the period of extended operation requested in the renewed application). 

For example, for an existing analysis that is part of the CLB and is based on a 60-year time 

assumption, the analysis would not necessarily have to be identified as a TLAA for the initial 

license renewal request because it would not conform to the definition of a TLAA, as clarified in 

FRN No. 95-11136; however, if the same analysis was left unchanged in the CLB and was going 

to be relied upon for a proposed SLR period, the analysis would conform to the third criterion for 

TLAAs in 10 CFR 54.3(a) because the 60-year assumed life would form the updated current 

operating term basis for the proposed SLR period. 

The reviewer reviews the FSAR Supplement for each TLAA identified as being within the scope of 

the SLRA, as determined in accordance with the TLAA definition criteria in 10 CFR 54.3 and 

identified in accordance with the requirements in 10 CFR 54.21(c)(1). 
4.1-3 

4.1.3 Review Procedures 

For each area of review described in Subsection 4.1.1, the reviewer adheres to the following 

review procedures: 

The reviewer uses the plant FSAR (as updated) and other CLB documents, such as NRC staff 

safety evaluation reports (SERs), to perform the review. The reviewer selects analyses that the 

applicant did not identify as TLAAs that are likely to meet the six criteria identified in 

Subsection 4.1.2. The reviewer verifies that the selected analyses, not identified by the applicant 

as TLAAs, do not meet at least one of the following criteria: 

Sections 4.2 through 4.6 identify typical types of TLAAs for most plants. Information on the 

applicant’s methodology for identifying TLAAs also may be useful in identifying calculations that 

did not meet the six criteria below. 

1. Involve systems, structures, and components within the scope of license renewal, as 

delineated in 10 CFR 54.4(a). Chapter 2 of this Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) provides 

the reviewer guidance on the scoping and screening methodology, and on plant-level 

and various system-level scoping results. 

2. Consider the effects of aging. The effects of aging include, but are not limited to, loss of 

material, changes in dimension, changes in material properties, loss of toughness, loss of 

prestress, settlement, cracking, and loss of dielectric properties. 

3. Involve time-limited assumptions defined by the current operating term (e.g., 40 years). 

The defined operating term should be explicit in the analysis. Simply asserting that a 

component is designed for a service life or plant life is not sufficient. The assertion is 

supported by calculations or other analyses that explicitly include a time limit. 

4. Were determined to be relevant by the licensee in making a safety determination. 

Relevancy is a determination that the applicant makes based on a review of the 

information available. A calculation or analysis is relevant if it can be shown to have a 

direct bearing on the action taken as a result of the analysis performed. Analyses are 

also relevant if they provide the basis for a licensee’s safety determination, and, in the 

absence of the analyses, the applicant might have reached a different safety conclusion. 

5. Show capability of the system, structure, or component to perform its intended 

function(s), as delineated. Involve conclusions or provide the basis for conclusions 

related to 10 CFR 54.4(b). Analyses that do not affect the intended functions of systems, 

structures, and components are not TLAAs. 

6. Are contained or incorporated by reference in the CLB. The CLB includes the technical 

specifications as well as design basis information (as defined in 10 CFR 50.2), or 

licensee commitments documented in the plant-specific documents contained or 

incorporated by reference in the CLB, including but not limited to the FSAR, NRC SERs, 

the fire protection plan/hazards analyses, correspondence to and from the NRC, the 

quality assurance plan, and topical reports included as references to the FSAR. 

Calculations and analyses that are not contained in the CLB or not incorporated by 

reference in the CLB are not TLAAs. If a code of record is in the FSAR for particular 
4.1-4 

groups of structures or components, reference material includes all calculations called for 

by that code of record for those structures and components. 

TLAAs that need to be addressed are not necessarily those analyses that have been previously 

reviewed or approved by the NRC. The following examples illustrate TLAAs that need to be 

addressed that were not previously reviewed and approved by the NRC: 

 The FSAR states that the design complies with a certain national code and standard. A 

review of the code and standard reveals that it calls for an analysis or calculation. Some 

of these calculations or analyses will be TLAAs. The actual calculation was performed by 

the applicant to meet the code and standard. The specific calculation was not referenced 

in the FSAR. The NRC had not reviewed the calculation. In response to a generic letter 

(GL), a licensee submitted a letter to the NRC committing to perform a TLAA that would 

address the concern in the GL. The NRC had not documented a review of the applicant’s 

response and had not reviewed the actual analysis. 

The following examples illustrate analyses that are not TLAAs and need not be addressed under 

10 CFR 54.21(c): 

 Population projections (Section 2.1.3 of NUREG–0800) (Ref. 2). 

 Cost-benefit analyses for plant modifications. 

 Analysis with time-limited assumptions defined short of the current operating term of the 

plant, for example, an analysis for a component based on a service life that would not 

reach the end of the current operating term. 

The number and type of TLAAs vary depending on the plant-specific CLB. All six criteria set forth 

in 10 CFR 54.3 (and repeated in Subsection 4.1.2) must be satisfied to conclude that a calculation 

or analysis is a TLAA. Table 4.1-1 provides examples of how these six criteria may be applied 

(Ref. 3). Table 4.1-2 provides a list of generic TLAAs that are included in the SRP-SLR. 

Table 4.7-1 in SRP-SLR Section 4.7 provides examples of potential plant-specific TLAAs that have 

been identified by license renewal applicants. It is not expected that all applicants would identify 

all the analyses in these tables as TLAAs for their plants. Also, an applicant may perform specific 

TLAAs for its plant that are not shown in these tables. 

Criterion 3 for TLAAs in 10 CFR 54.3(a) establishes that, as one of the six criteria that are used to 

define a given analysis as a TLAA, the analysis has to involve time-limited assumptions defined 

by the current operating term (e.g., 40 years). Therefore, for proposed SLRAs, there may be 

instances where an existing, time-dependent analysis did not conform to Criterion 3 for TLAAs in 

10 CFR 54.3(a) for the current period of extended operation, but would conform to this criterion for 

the subsequent period of extended operation that is requested for NRC approval. Therefore, the 

reviewer should perform a review of the CLB to determine whether there are any existing 

analyses for the CLB that will need to be identified as analyses that conform to Criterion 3 for 

TLAAs for the proposed subsequent period of extended operation even though the analyses did 

not conform to Criterion 3 for TLAAs for the previous period of extended operation that was 

approved in the renewed operating license for that period. For those cases where the addition of 

a proposed subsequent period of extended operation would cause a given analysis to conform to 

Criterion 3 for TLAAs in 10 CFR 54.3(a), the reviewer should assess whether the analysis also 

conforms to the remaining five criteria for identifying TLAAs in 10 CFR 54.3(a), and determine 
4.1-5 

whether the analysis needs to be identified as a TLAA for the subsequent period of extended 

operation in accordance with the requirement in 10 CFR 54.21(c)(1). 

As appropriate, NRC staff from other branches of the Office of Nuclear Reactor Regulation review 

the application in their assigned areas without examining the identification of TLAAs. However, 

they may come across situations in which they may question why the applicant did not identify 

certain analyses as TLAAs. The reviewer coordinates the resolution of any such questions with 

these other NRC staff to determine whether these analyses should be evaluated as TLAAs. 

In order to determine whether there is reasonable assurance that the applicant has identified the 

TLAAs for its plant, the reviewer should find that the analyses omitted from the applicant’s list are 

not TLAAs. Should an applicant identify a TLAA that is also a basis for a plant-specific exemption 

that was granted pursuant to 10 CFR 50.12 and the exemption is in effect for the current operating 

period, the reviewer verifies that the applicant also has identified that exemption pursuant to 

10 CFR 54.21(c)(2). Examples of an exemptions that may have been granted in accordance with 

10 CFR 50.12 and based on a TLAA are those NRC-granted exemptions that approved American 

Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) case N-514 as 

an alternative basis for complying with the pressure lift and system enable temperature set point 

requirements for pressurized water reactors (PWRs) low temperature overpressure protection 

systems in 10 CFR Part 50, Appendix G and the ASME Code Section XI, Appendix G. 

4.1.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this section, and whether the NRC staff’s evaluation supports conclusions of the 

following type, to be included in the SER: 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has provided an acceptable list of TLAAs as defined in 10 CFR 54.3, 

and that no 10 CFR 50.12 exemptions have been granted on the basis of a 

TLAA, as defined in 10 CFR 54.3. 

4.1.5 References 

1. NRC. “Nuclear Power Plant License Renewal; Revisions.” Federal Register: Vol. 60. 

No. 88, pp. 22,461–22,495. May 8, 1995.

2. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

Nuclear Power Plants.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML070630046. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 2007. 

3. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. ADAMS Accession 

No. ML051860406. Washington, DC: Nuclear Energy Institute. June 2005. 

 
4.1-6 

Table 4.1-1 Sample Process for Identifying Potential Time-Limited Aging Analyses 

(TLAAs) and Basis for Disposition 

Example of an analysis that meets all six of the criteria in 10 CFR 54.3(a) for defining an analysis 

as a TLAA: The CLB includes a time-dependent fatigue flaw growth analysis for the reactor coolant 

pump (RCP) flywheels. An age-related fatigue failure of flywheels could potentially be a source of 

missiles that have the potential to impact the structural integrity and pressure retaining function of the 

reactor coolant pressure boundary. The applicant has identified that the RCP flywheels are components 

that meet the scoping definition in Title 10 of the Code of Federal Regulations (10 CFR) 54.4(a)(1), in that 

the flywheels assure adequate heat removal during a plant trip and loss of power to the RCPs, as well as 

initiation of natural circulation flow as part of necessary safe shutdown activities. 

The applicant has not included the RCP flywheels as components that need to be within the scope of an 

aging management review (AMR), as would otherwise be required in accordance with 10 CFR 

54.21(a)(1). The analysis is referenced in the updated final safety analysis report (UFSAR) and is based 

on design basis transients that are assumed and evaluated in the UFSAR based on a 40-year design life. 

The analysis is relied upon to establish a 10-year augmented inservice inspection interval for performing 

inspections of RCP flywheels and to demonstrate that fatigue-induced growth of a flaw in the flywheels 

would not result in a flywheel missile that could threaten the structural integrity of the reactor coolant 

pressure boundary during the life of the plant.

Criterion in 

10 CFR 54.3(a) Disposition Basis for Comparing to the Criterion in 10 CFR 54.3(a) 

Criterion 1: The 

analysis must 

involve systems, 

structures, and 

components within 

the scope of 

license renewal, 

as delineated in 

10 CFR 54.4(a).

Although the RCP flywheels as active components do not need to be subjected to 

an AMR [as defined in 10 CFR 54.21(a)(1)], the components are within the scope of 

license renewal application because their failure could impact the intended pressure 

retaining function of a component that is located in the reactor coolant pressure 

boundary (RCPB). Therefore, the fatigue flaw growth analysis does conform to 

Criterion 1 in 10 CFR 54.3(a) because the flywheels do need to be within the scope 

of license renewal as a component whose failure could impact the intended function 

of a component that has been scoped in for renewal in accordance with 

10 CFR 54.4(a)(1). 

Criterion 2: The 

analysis must 

consider the 

effects of aging.

The fatigue flaw growth analysis for the RCP flywheels does meet Criterion 2 

because the analysis assumes the presence of a postulated crack in the 

components and assumes that an age-related growth mechanism (fatigue flaw 

growth) will grow the flaw under the assumed transient loading conditions for the 

analysis. 

Criterion 3: The 

analysis must 

involve timelimited 

assumptions 

defined by the 

current operating 

term (for example, 

40 years).

The fatigue flaw growth analysis for the RCP flywheels does meet Criterion 3 

because the analysis assumes that the loading conditions that induced fatigue flaw 

growth in the flywheel discs are based on the 40-year cyclic transient assumptions 

for specific design transients in the UFSAR. The 40-year cyclical nature of this 

assumption defines this analysis as one that involves time-limited assumptions 

defined by the current operating term. 

Criterion 4: The 

analysis must be 

determined to be 

relevant by the 

licensee in making 

a safety 

determination.

The analysis conforms to Criterion 4 because the applicant is relying on the fatigue 

flaw growth analysis to establish a safety-related decision at the facility, which 

amounts to the applicant’s safety decision to perform augmented inservice 

inspection of the RCP flywheels on a 10-year inservice inspection interval and 

relates to the applicant’s basis for maintaining the integrity of the reactor coolant 

pressure boundary during the life of the plant. 
4.1-7 

Table 4.1-1 Sample Process for Identifying Potential Time-Limited Aging Analyses 

(TLAAs) and Basis for Disposition 

Criterion 5: The 

analysis must 

involve 

conclusions or 

provide the basis 

for conclusions 

related to the 

capability of the 

system, structure, 

or component to 

perform its 

intended 

function(s), as 

delineated in 

10 CFR 54.4(b).

The analysis conforms to Criterion 5 because the analysis evaluates the structural 

integrity of the RCP flywheels for fatigue-induced growth to ensure the integrity of 

the flywheels will be maintained during the licensed period of operation for the 

facility and that the integrity of the reactor coolant pressure boundary will be 

protected against the consequences of postulated flywheel missiles during the life of 

the plant. 

Criterion 6: The 

analysis is 

contained or 

incorporated by 

reference in the 

CLB.

The analysis conforms to Criterion 6 because the analysis is referenced in the 

UFSAR for the facility. 

Example of analyses that do not meet the six of the criteria for TLAAs in 10 CFR 54.3(a):

Example of an 

analysis that does 

not meet 

Criterion 1 in 

10 CFR 54.3(a): 

The analysis must 

involve systems, 

structures, and 

components within 

the scope of 

license renewal, 

as delineated in 

10 CFR 54.4(a).

The CLB includes a time-dependent corrosion analysis for both a refueling water 

storage tank (RWST) and a standby RWST that are included in the plant design. 

The applicant can align the standby RWST to the safety injection system and 

containment spray system for the facility during a postulated loss-of-coolant 

accident and the applicant has performed a 40-year time-dependent corrosion 

analysis of both the RWST and standby RWST. The RWST is credited as a safetyrelated component that is credited for accident mitigation objectives in the plant’s 

accident analyses that are defined and evaluated in the UFSAR. In contrast, the 

standby RWST is not credited for accident mitigation in the accident analyses 

defined in the UFSAR. A postulated failure of the standby RWST does not have the 

ability to impact the intended function [as defined in 10 CFR 54.4(b)] of any safetyrelated component or structure that is required to be scoped in for renewal in 

accordance with 10 CFR 54.4(a)(1); nor is the standby RWST within the scope of 

any special regulations, as defined in 10 CFR 54.4(a)(3). The applicant has not 

identified the standby RWST as a tank that is within the scope of license renewal. 

Although the corrosion analysis for the standby RWST is part of the plant design, 

the analysis does not apply to a plant component that is within the scope of the 

SLRA because the component is not required to be within the scope of the license 

renewal application in accordance with 10 CFR 54.4 (a)(1), (a)(2), or (a)(3). 

Therefore, under this example, the corrosion analysis for the standby RWST does 

meet Criterion 1 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in 

the 10 CFR Part 54 rule. 
4.1-8 

Table 4.1-1 Sample Process for Identifying Potential Time-Limited Aging Analyses 

(TLAAs) and Basis for Disposition 

Example of an 

analysis that 

does not meet 

Criterion 2 in 

10 CFR 54.3(a): 

The analysis must 

consider the 

effects of aging.

The CLB and design basis includes a stress analysis for a reactor coolant loop 

elbow that is compared to American Society of Mechanical Engineers Boiler and 

Pressure Vessel Code (ASME Code) Section III allowable stress values. The 

stress analysis is performed in accordance with ASME Code Section III 

requirements, as invoked by 10 CFR 50.55a requirements. 

Although the stress analysis is required by the U.S. Nuclear Regulatory 

Commission (NRC) regulations and ASME Code requirements and is part of the 

CLB, it does not involve any analysis of an applicable or postulated aging effect. 

Therefore, under this example, the analysis does not conform to Criterion 2 in 10 

CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 

Example of an 

analysis that 

does not meet 

Criterion 3 in 

10 CFR 54.3(a): 

The analysis must 

involve timelimited 

assumptions 

defined by the 

current operating 

term (for example, 

40 years).

The applicant has detected a flaw in one of its reactor vessel nozzle-to-safe end 

welds and has performed an ASME Code Section XI inservice inspection flaw 

growth analysis of the flaw in the components to justify further service of the 

impacted weld until the next outage in which the flaw would be inspected for 

acceptability, without the need of repair or replacement. The ASME-based flaw 

evaluation is part of the CLB and assumes the Class 1 design basis transients 

occur over a 20-year period from the time the flaw was detected. 

The analysis does not involve time-dependent assumptions defined by the current 

operating period because the assessment of design basis transient cycles was 

made on a time period less than that used for the current operating term. 

Therefore, under this example, the fatigue flaw analysis would not conform to 

Criterion 3 in 10 CFR 54.3(a) and would not meet the definition of a TLAA in the 10 

CFR Part 54 rule. 

Example of an 

analysis that 

does not meet 

Criterion 4 in 

10 CFR 54.3(a): 

The analysis must 

be determined to 

be relevant by the 

licensee in making 

a safety 

determination.

The original licensing basis for a PWR included a high-energy line break (HELB) 

analysis for a piping location in the main reactor coolant loop that was based on 

ASME Code Section III cumulative usage factor (CUF) analysis requirements for 

high energy line break locations and demonstrated the need for inclusion of a pipe 

whip restraint in the design of the piping location. Subsequent to the performance 

of this analysis, the applicant submitted a leak-before-break (LBB) analysis for the 

main coolant loop piping that demonstrated conformance with the revised dynamic 

effect requirements in NRC General Design Criterion 4. The results of the LBB 

analysis demonstrated that the licensee would be capable of detecting a leak in the 

affected piping prior to a catastrophic failure of the component and that the pipe 

whip restraints could be removed from the design of the component. The LBB 

analysis was approved as part of an update of the CLB for the facility such that the 

HELB analysis is no longer relied upon as part of the CLB for this piping location. 

The original HELB analysis for this piping location is no longer relied upon for the 

CLB because it was replaced by the NRC-approved LBB analysis for the main 

coolant loops, which included these piping locations. Therefore, the original HELB 

analysis for this piping location is not relevant in making a safety determination 

relative to the inclusion of a pipe whip restraint on the piping component. Under this 

example, the HELB analysis for this specific piping location does not conform to 

Criterion 4 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 

CFR Part 54 rule. HELB analyses for piping locations not excluded by LBB would 

still be relied upon for the CLB and would need to be identified as TLAAs for the 

SLRA. 
4.1-9 

Table 4.1-1 Sample Process for Identifying Potential Time-Limited Aging Analyses 

(TLAAs) and Basis for Disposition 

Example of an 

analysis that 

does not meet 

Criterion 5 in 

10 CFR 54.3(a): 

The analysis must 

involve 

conclusions or 

provide the basis 

for conclusions 

related to the 

capability of the 

system, structure, 

or component to 

perform its 

intended 

function(s), 

as delineated in 

10 CFR 54.4(b).

The original licensing basis for a BWR included an evaluation of the number of paint 

coats that would be applied to the inside surfaces of its condensate storage tanks 

(CSTs). The CSTs have been included in the scope of the license renewal 

application in accordance with 10 CFR 54.4(a)(1) requirements and are within the 

scope of an applicable AMR, as performed in accordance with 10 CFR 54.21(a)(1) 

requirements. Although the coating analysis for the inside surfaces of the CST is 

discussed in the UFSAR, the UFSAR states that the analysis is not relied upon for 

the structural integrity of the CST or for drawing a conclusion that the CST will fulfill 

its accident mitigation and safe shutdown functions. 

Although the coating analysis is part of the design basis, it is not used to draw a 

conclusion or provide the basis for concluding that the structural integrity of the CST 

walls will be maintained during the design life of the plant or the ability of the CST 

coolant inventory to meet the accident mitigation or safe shutdown objectives for the 

plant design. Therefore, the coating analysis for the CST does not involve 

conclusions or provide the basis for conclusions related to the capability of the CST 

to perform its intended functions, as defined in 10 CFR 54.4(b). Under this 

example, the coating analysis for the CST does not conform to Criterion 5 in 10 

CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 

Example of an 

analysis that 

does not meet 

Criterion 6 in 

10 CFR 54.3(a): 

The analysis is 

contained or 

incorporated by 

reference in the 

CLB.

The CLB for a PWR includes a plant-specific, probabilistic main turbine missile 

analysis that is used as basis for meeting 10 CFR Part 50, Appendix A, dynamic 

effect analysis design requirements, as given in General Design Criterion 4, 

“Dynamic Effects.” This analysis is described and evaluated in the UFSAR, and 

states that the analysis was performed to demonstrate the main turbines will not 

generate a missile that could threaten the integrity of safety-related structures and 

components in the facility. The UFSAR indicates that the probabilistic turbine 

missile analysis was performed in lieu of a generic time-dependent turbine missile 

analysis that is provided in a specific vendor report and that meets all six of the 

criteria for defining TLAAs in 10 CFR 54.3(a). 

In this case, although the generic time dependent turbine missile analysis in the 

vendor report could have been relied upon for the CLB, the applicant does not rely 

on the analysis in this report as its basis for meeting General Design Criterion 4 

requirements in 10 CFR Part 50, Appendix A. Therefore, the generic analysis in the 

vendor report is not contained or incorporated by reference in the CLB. Under this 

example, the generic turbine missile analysis in the vendor report does not conform 

to Criterion 6 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 

10 CFR Part 54 rule. 

 
4.1-10 

Table 4.1-2 Generic Time-Limited Aging Analyses 

Reactor Vessel Neutron 

Embrittlement (Subsection 4.2) 

Neutron Fluence 

Pressurized Thermal Shock (PWRs Only) 

Upper Shelf Energy (PWRs and BWRs) 

Pressure Temperature (P-T) Limits (PWRs and BWRs) 

Low Temperature Overpressure Protection System 

Setpoints (PWRs Only) 

Ductility Reduction Evaluation for Reactor Internals 

(B&W designed PWRs only) 

RPV Circumferential Weld Relief–Probability of Failure 

and Mean Adjusted Reference Temperature Analysis 

for the RPV Circumferential Welds (BWRs only) 

Reactor Vessel Axial Weld Probability of Failure and 

Mean Adjusted Reference Temperature Analysis 

(BWRs only) 

Metal Fatigue (Subsection 4.3) Metal Fatigue of Class 1 Components 

Metal Fatigue of Non-Class 1 Components 

Environmentally-Assisted Fatigue 

High Energy Line Break Analyses 

Cycle-dependent Fracture Mechanics or Flaw 

Evaluations 

Cycle-dependent Fatigue Waivers 

Environmental Qualification of Electrical Equipment (Subsection 4.4) 

Concrete Containment Tendon Prestress (Subsection 4.5) 

Containment Liner Plate, Metal Containments, and Penetrations Fatigue (Subsection 4.6) 
4.2-1 

4.2 Reactor Pressure Vessel Neutron Embrittlement Analyses 

Review Responsibilities 

Primary—Branch(es) responsible for the time-limited aging analysis (TLAA) issues 

Secondary—Branch responsible for reactor systems 

4.2.1 Areas of Review 

During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in the 

reactor pressure vessel (RPV) beltline region of light-water nuclear power reactors, where RPV 

beltline region is described in Regulatory Issue Summary (RIS) 2014-11 (Ref. 1). Areas of review 

to ensure that the RPV has adequate fracture toughness to prevent brittle failure during normal 

and off-normal operating conditions are: (a) neutron fluence, (b) upper-shelf energy (USE), 

(c) pressurized thermal shock (PTS) for pressurized water reactor (PWRs), (d) heat-up and 

cool-down (pressure-temperature limits) curves, (e) Boiling Water Reactor Vessel and Internals 

Project (BWRVIP)-05 analysis for elimination of circumferential weld inspection and analysis of 

the axial welds, and (f) other plant-specific TLAAs on RPV neutron embrittlement. The adequacy 

of the analyses for these five areas is reviewed for the subsequent period of extended operation. 

The branch responsible for reactor systems reviews neutron fluence and dosimetry information in 

the application. 

4.2.2 Acceptance Criteria 

The acceptance criteria for the areas of review described in Subsection 4.2.1 of this review plan 

section delineate acceptable methods for meeting the requirements of the U.S. Nuclear 

Regulatory Commission (NRC) regulation in Title 10 of the Code of Federal Regulations

(10 CFR) 54.21(c)(1) (Refs. 2, 3).3

4.2.2.1 Time-Limited Aging Analyses 

Pursuant to 10 CFR 54.21(c)(1)(i)–(iii), an applicant must demonstrate one of the following: 

(i) The analyses remain valid for the period of extended operation; 

(ii) The analyses have been projected to the end of the period of extended operation; or 

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation. 

For the first three areas of review for the analysis of RPV neutron embrittlement, the specific 

acceptance criteria depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii).

 

3For subsequent license renewal applications, the period of extended operation concerns the period of operation after 

the expiration of the renewed license (i.e., operation from 60 to 80 years). 
4.2-2 

4.2.2.1.1 Neutron Fluence 

Neutron fluence is the number of neutrons accumulated per unit area during a certain period 

of neutron irradiation. An RPV neutron fluence analysis involves time-limited assumptions 

(e.g., 40 years of original design life) and is used to determine the loss of fracture toughness due 

to neutron irradiation embrittlement of the RPV. Appendix H to 10 CFR Part 50 (Ref. 4) requires 

that an applicant must implement an RPV Surveillance program for an RPV if the peak neutron 

fluence at the end of the design life of the RPV exceeds a neutron fluence of 1017 n/cm2

(E > 1 MeV). The RPV neutron fluence analysis is also integral to other neutron embrittlement 

TLAAs (e.g., USE and pressure-temperature (P-T) limits analyses) because neutron fluence is a 

fundamental parameter which is used to determine the level of neutron irradiation embrittlement of 

an RPV. As discussed above, the RPV neutron fluence analysis is important in making a safety 

determination for an RPV in terms of loss of fracture toughness due to neutron 

irradiation embrittlement. 

Typically, the RPV neutron fluence analysis is described in the applicant’s Final Safety Analysis 

Report (FSAR) or other design documents approved by NRC. In its subsequent license renewal 

application (SLRA), the applicant identifies: (a) the neutron fluence for each beltline material at 

the end of extended license term, (b) the NRC staff-approved methodology used to calculate the 

neutron fluence or submits the methodology for NRC staff review, (c) whether the methodology is 

consistent with the guidance in NRC Regulatory Guide (RG) 1.190 (Ref. 5), and (d) how the 

neutron fluence is monitored during the subsequent period of extended operation. An applicant 

may take any one of the following three dispositions for the RPV neutron fluence analysis. 

4.2.2.1.1.1 10 CFR 54.21(c)(1)(i) 

A neutron fluence analysis typically accounts for planned operation by including assumptions 

regarding the neutron flux emitted from the core. The flux is integrated over time to yield the 

estimated fluence. Frequently, neutron fluence calculations will include projected fluence values 

for multiple periods of exposure, (e.g., 40, 60, and 80 calendar years). In order to use a 

disposition for fluence pursuant to 10 CFR 54.21(c)(1)(i), the applicant will demonstrate the 

existing RPV neutron fluence analysis, including the projected flux for planned operation, in the 

current licensing basis (CLB) remains valid during the subsequent period of extended operation. 

The fluence calculation will be re-evaluated to confirm its validity. 

4.2.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

For a disposition in accordance with 10 CFR 54.21(c)(1)(ii), the applicant will provide new or 

updated calculations that address the fluence effects during the subsequent period of extended 

operation. The new or updated RPV neutron fluence analysis is evaluated to consider the 

subsequent period of extended operation in accordance with (1) NRC RG 1.190, or (2) a 

methodology that has been approved for use by the NRC. 

4.2.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

In the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report 

Aging Management Program (AMP) X.M2, “Neutron Fluence Monitoring,” the NRC staff has 

evaluated an AMP for projecting and monitoring neutron fluence for the subsequent period of 

extended operation. The staff has determined that this program is acceptable to project and 

monitor neutron fluence as a basis for managing loss of fracture toughness due to neutron 

irradiation embrittlement of RPVs in accordance with 10 CFR 54.21(c)(1)(iii). 
4.2-3 

4.2.2.1.2 Upper-Shelf Energy 

10 CFR Part 50 Appendix G (Ref. 6) paragraph IV.A.1 requires that the RPV beltline materials 

have a Charpy USE of no less than 68 J (50 ft-lb) throughout the life of the RPV, unless otherwise 

approved by the NRC. An applicant may take any one of the following three approaches. 

4.2.2.1.2.1 10 CFR 54.21(c)(1)(i) 

The RPV components evaluated in the existing USE analysis or NRC-approved equivalent 

margins analysis (EMA) are reevaluated to demonstrate that the existing analysis remains valid 

during the subsequent period of extended operation because the neutron fluence projected to the 

end of the subsequent period of extended operation is bounded by the neutron fluence in the 

existing USE analysis or NRC-approved EMA. 

4.2.2.1.2.2 10 CFR 54.21(c)(1)(ii) 

The RPV components evaluated in the existing USE analysis or NRC-approved EMA are 

reevaluated to consider the subsequent period of extended operation in accordance with 

10 CFR Part 50, Appendix G. 

10 CFR Part 50, Appendix G, Section IV.A.1, requires applicants to take further corrective actions 

where the 68 Joule (J) (50 ft-lb) end-of-life (EOL) USE criterion cannot be met. When this occurs, 

a licensee is required to submit a supplemental analysis for NRC approval. The applicant will 

need to submit a plant-specific engineering analysis (usually an EMA) for NRC approval as 

supplemental information for subsequent license renewal (SLR). Otherwise, failure to meet the 

USE requirements of 10 CFR Part 50, Appendix G for the RPV materials as evaluated using the 

neutron fluence that are projected for the subsequent period of extended operation mandates 

imposition of additional commitments or license conditions on USE for the SLRA. 

4.2.2.1.2.3 10 CFR 54.21(c)(1)(iii) 

Acceptance criteria for accepting USE TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) have yet 

to be developed. They will be evaluated on a case-by-case basis to ensure that the aging effects 

will be managed such that the intended function(s) will be maintained during the subsequent 

period of extended operation. 

4.2.2.1.3 Pressurized Thermal Shock (for PWRs) 

For PWRs, 10 CFR 50.61 (Ref. 7) requires that the reference temperature for RPV beltline 

materials evaluated at the neutron fluence corresponding to the end of the subsequent period of 

extended operation [i.e., reference temperature for pressurized thermal shock (RTPTS)] be less 

than the PTS screening criteria at the expiration date of the operating license, unless otherwise 

approved by the NRC. The PTS screening criteria are 132 °C (Celsius) [270 °F (Fahrenheit)] for 

plates, forgings, and axial weld materials, and 149 °C (300 °F) for circumferential weld materials. 

Alternatively, the licensee may comply with the requirements of 10 CFR 50.61a (Ref. 8). The 

regulations require updating of the PTS assessment upon a request for a change in the expiration 

date of a facility’s operating license, or whenever there is a significant change in projected values 

of RTPTS. Therefore, the RTPTS value must be calculated for the entire licensed operating period of 

the facility, including the subsequent period of extended operation. If the analyses result in RTPTS

values that exceed the PTS screening criteria at the end of the subsequent period of extended 
4.2-4 

operation, the applicant is required to implement additional corrective actions as described in 

10 CFR 50.61 or 10 CFR 50.61a. The PTS TLAA may be handled as follows. 

4.2.2.1.3.1 10 CFR 54.21(c)(1)(i) 

The existing PTS analysis based on 10 CFR 50.61 remains valid during the subsequent period of 

extended operation because the neutron fluence projected to the end of the subsequent period of 

extended operation is bounded by the neutron fluence assumed in the existing analysis. If the 

existing PTS analysis is based on 10 CFR 50.61a, the applicant demonstrates that the current 

analysis remains applicable for the subsequent period of extended operation. 

4.2.2.1.3.2 10 CFR 54.21(c)(1)(ii) 

The PTS analysis is reevaluated to consider the subsequent period of extended operation in 

accordance with 10 CFR 50.61 or 10 CFR 50.61a. If the analyses result in RTPTS values that 

exceed the PTS screening criteria at the end of the subsequent period of extended operation, the 

applicant is required to implement additional corrective actions as described in 10 CFR 50.61 or 

10 CFR 50.61a. If the existing PTS analysis is based on 10 CFR 50.61a, the applicant updates 

the submittal to reflect the subsequent period of extended operation. 

4.2.2.1.3.3 10 CFR 54.21(c)(1)(iii) 

The NRC staff position for license renewal (LR) on this option is described in a May 27, 2004 

letter from L.A. Reyes to the Commission (Ref. 9), which states that if the applicant does not 

extend the TLAA, the applicant provides an assessment of the CLB TLAA for PTS, a discussion of 

the flux reduction program implemented in accordance with 10 CFR 50.61(b)(3), if necessary, and 

an identification of the viable options that exist for managing the aging effect in the future. 

4.2.2.1.4 Pressure-Temperature Limits 

10 CFR Part 50, Appendix G, requires that the RPV be maintained within established P-T limits 

during normal operating conditions of the plant (including heat-ups and cool-downs of the reactor 

and anticipated operational transients), and during pressure tests and system leak tests. These 

limits specify the maximum allowable pressure as a function of reactor coolant temperature. As 

the RPV becomes embrittled and its fracture toughness is reduced, the allowable pressure (given 

the required minimum temperature) is reduced. RIS 2014-11 clarifies issues that must be 

addressed in developing P-T limits. 

P-T limits are TLAAs for the application if the plant currently has P-T limit curves approved for the 

expiration of the current period of operation (e.g., 32 effective full-power year (EFPY) or some 

other licensed EFPY value defined for the expiration date of the current license). However, the 

P-T limits for the subsequent period of extended operation need not be submitted as part of the 

SLRA since the P-T limits need to be updated through the 10 CFR 50.90 (Ref. 10) licensing 

process when necessary for P-T limits that are located in the limiting conditions of operations 

(LCOs) of the Technical Specifications (TS). For those plants that have approved 

pressure-temperature limit reports (PTLRs), the P-T limits for the subsequent period of extended 

operation will be updated at the appropriate time through the plant’s Administrative Section of the 

TS and the plant’s PTLR process. In either case, the 10 CFR 50.90 or the PTLR processes, 

which constitute the CLB, will ensure that the P-T limits for the subsequent period of extended 

operation will be updated prior to expiration of the P-T limit curves for the current period 

of operation. 
4.2-5 

P-T limits may be handled as follows. 

4.2.2.1.4.1 10 CFR 54.21(c)(1)(i) 

The applicant demonstrates (on a case-by-case basis) that existing P-T limits in the CLB will 

remain valid during the subsequent period of extended operation. 

4.2.2.1.4.2 10 CFR 54.21(c)(1)(ii) 

The P-T limits are updated for the subsequent period of extended operation in accordance with 

10 CFR Part 50, Appendix G and the applicant’s appropriate TS change process for updating the 

P-T limit curves. 

For P-T limit curves that are included in and controlled by requirements in the limiting conditions of 

operations of the plant TS, the applicant submits the changes to the P-T limits as a license 

amendment request (i.e., a TS change request) for the SLRA that is submitted in accordance with 

the requirements in 10 CFR 54.22 (Ref. 11) and uses the license amendment submittal as the 

basis for accepting the TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

For P-T limits that are controlled by Administrative Controls TS requirements and located in an 

NRC-approved PTLR, the applicant updates the P-T limits in accordance with the methodology or 

methodologies approved in the applicable Administrative Controls TS section for its PTLR process 

and submits the updated PTLR(s) containing the updated P-T limits to the NRC (as information) in 

accordance the reporting requirements in the applicable Administrative Controls TS section. The 

applicant uses the submittal of the updated PTLR as the basis for accepting the TLAA in 

accordance with 10 CFR 54.21(c)(1)(ii). 

4.2.2.1.4.3 10 CFR 54.21(c)(1)(iii) 

Updated P-T limits for the subsequent period of extended operation must be established and 

completed using the applicable TS change process for updating the P-T limit curves prior to the 

plant’s entry into the subsequent period of extended operation. The 10 CFR 50.90 process for 

P-T limits located in the LCOs or the Administrative Controls Process for P-T limits that are 

administratively amended through a PTLR process can be considered adequate AMPs or aging 

management activities within the scope of 10 CFR 54.21(c)(1)(iii), such that P-T limits will be 

maintained through the subsequent period of extended operation. 

4.2.2.1.5 Elimination of Boiling Water Reactor Circumferential Weld Inspections 

Some boiling water reactors (BWRs) have an approved technical alternative in the CLB, which 

eliminates the RPV circumferential shell weld inspections from the American Society of 

Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) Section XI program for the 

current license term. Approved technical alternatives for SLR have yet to be developed. If these 

analyses are identified as TLAAs, they will be evaluated on a case-by-case basis in accordance 

with the requirements in 10 CFR 54.21(c)(1). 

4.2.2.1.6 Boiling Water Reactor Axial Welds 

Those BWRs that have been approved to use the circumferential weld technical alternative 

performed acceptable conditional probability of failure analyses of their RPV axial shell welds. 

Approved technical alternatives for SLR have yet to be developed. If these analyses are identified 
4.2-6 

as TLAAs, they will be evaluated on a case-by-case basis in accordance with the requirements 

in 10 CFR 54.21(c)(1). 

4.2.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59 (Ref. 12). The 

description contains information associated with the TLAAs regarding the basis for determining 

that the applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

4.2.3 Review Procedures 

For each area of review described in Subsection 4.2.1, the following review procedures should 

be followed. 

4.2.3.1 Time-Limited Aging Analyses 

For the first four areas of review for the analysis of RPV neutron embrittlement, the review 

procedures depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). For each area, 

the applicant’s three options under Section 54.21(c)(1) are discussed in turn. 

The applicant may identify activities to be performed to verify the assumption basis of the neutron 

fluence calculations that are used to evaluate the RPV neutron embrittlement analyses. An 

evaluation of that verification activity is provided by the applicant in the SLRA. The reviewer 

assures that the applicant’s verification activity is sufficient to confirm the calculation assumptions 

for the 80-year period. If the assumption basis is not verified, the applicant must reevaluate the 

analysis and take appropriate corrective actions as necessary, consistent with the requirements of 

the affected regulation. 

4.2.3.1.1 Neutron Fluence 

4.2.3.1.1.1 10 CFR 54.21(c)(1)(i) 

The reviewer confirms that the applicant’s existing RPV neutron fluence analysis remains valid 

during the subsequent period of extended operation. The reviewer also confirms that the 

applicant identifies: (a) the neutron fluence for each beltline material at the end of the subsequent 

period of extended operation, (b) the NRC staff-approved methodology used to determine the 

neutron fluence or submits the methodology for NRC staff review, and (c) whether the 

methodology is consistent with the guidance in NRC RG 1.190.

4.2.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

The reviewer confirms that the applicant adequately reevaluated its RPV neutron fluence analysis 

for the subsequent period of extended operation. As part of its review, the review confirms that 

the applicant identifies: (a) the neutron fluence for each beltline material at the end of the 

subsequent period of extended operation, (b) the NRC staff-approved methodology used to 

determine the neutron fluence or submits the methodology for NRC staff review, and (c) whether 

the methodology is consistent with the guidance in NRC RG 1.190. 
4.2-7 

4.2.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

GALL-SLR Report AMP X.M2, “Neutron Fluence Monitoring” provides an acceptable method to 

project and monitor RPV neutron fluence through the subsequent period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(iii). The NRC staff reviews an applicant’s program for 

dispositioning the TLAA in accordance with the requirements in 10 CFR 54.21(c)(1)(iii) and the 

guidance in GALL-SLR Report AMP X.M2. Plant-specific approaches to projecting and 

monitoring neutron fluence will be evaluated on a case-by-case basis to ensure that the aging 

effects due to neutron irradiation embrittlement will be managed such that the intended 

functions(s) will be adequately maintained for the subsequent period of extended operation. 

4.2.3.1.2 Upper-Shelf Energy 

4.2.3.1.2.1 10 CFR 54.21(c)(1)(i) 

The projected 1⁄4T neutron fluence at the end of the subsequent period of extended operation is 

reviewed for all beltline materials to verify that it is bounded by the neutron fluence assumed in the 

existing USE or NRC-approved EMA analysis in the CLB. 

4.2.3.1.2.2 10 CFR 54.21(c)(1)(ii) 

The documented results of the revised USE analysis (or revised EMA analysis, as applicable) 

based on the projected neutron fluence at the end of the subsequent period of extended operation 

are reviewed for compliance with 10 CFR Part 50, Appendix G. The applicant may use NRC 

RG 1.99 Rev. 2 (Ref. 13) as the basis for using the 1⁄4T neutron fluence values for the reactor 

vessel beltline components (as projected to the end of the SLR period) to project the USE values 

for the reactor vessel beltline components at the end of the subsequent period of extended 

operation. The applicant also may use ASME Code Section XI Appendix K (Ref. 14) for the 

purpose of performing an equivalent margins analysis to demonstrate that adequate protection 

for ductile failure is maintained to the end of the subsequent period of extended operation. The 

NRC staff reviews the applicant’s methodology for this evaluation. Branch Technical Position 

(BTP) 5-3, “Fracture Toughness Requirements,” in Standard Review Plan (Ref. 15), Section 5.3.2, 

“Pressure Temperature Limits, Upper-Shelf Energy, and Pressurized Thermal Shock,” provides 

additional NRC positions on estimations of USE values for RPV beltline materials. 

The NRC staff confirms that the applicant has provided sufficient information for all USE and/or 

equivalent margins analysis calculations for the subsequent period of extended operation 

as follows: 

The applicant identifies the neutron fluence at the 1⁄4T location for each beltline 

material at the expiration of the subsequent period of extended operation. 

To confirm that the USE analysis meets the requirements of Appendix G of 10 CFR Part 50 at the 

end of the subsequent period of extended operation, the NRC staff determines whether: 

1. For each beltline material, the applicant provides the unirradiated USE and the projected 

USE at the end of the subsequent period of extended operation, and whether the drop in 

USE was determined using the limit lines in Figure 2 of NRC RG 1.99, Rev 2, based on 

the material copper content, or from surveillance data. 
4.2-8 

2. If an equivalent margins analysis is used to demonstrate compliance with the USE 

requirements in Appendix G of 10 CFR Part 50, the applicant provides the analysis or 

identifies an NRC-approved topical report that contains the analysis which is applicable 

to the subsequent period of extended operation. Information the NRC staff considers to 

assess the equivalent margins analysis includes the unirradiated USE (if available) for 

the material, its copper content, the neutron fluence (1⁄4T and at 1-inch depth), the 

projected SLR USE, the operating temperature in the downcomer at full power, the 

vessel radius, the vessel wall thickness, the J-applied analysis for Service Level C and 

D, the vessel accumulation pressure, and the vessel bounding heat-up/cool-down rate 

during normal operation. 

4.2.3.1.2.3 10 CFR 54.21(c)(1)(iii) 

The applicant’s proposal to demonstrate that the effects of aging on the intended function(s) 

will be adequately managed for the subsequent period of extended operation is reviewed on a 

case-by-case basis. 

4.2.3.1.3 Pressurized Thermal Shock (for Pressurized Water Reactors) 

4.2.3.1.3.1 10 CFR 54.21(c)(1)(i) 

The projected clad-to-base metal interface neutron fluence at the end of the subsequent period of 

extended operation is reviewed to verify that it is bounded by the neutron fluence assumed in the 

existing PTS analysis. 

For PTS analysis based on an NRC-approved submittal based on 10 CFR 50.61a, the applicant 

demonstrates that the analysis bounds the subsequent period of extended operation. 

4.2.3.1.3.2 10 CFR 54.21(c)(1)(ii) 

The documented results of the revised PTS analysis based on the projected neutron fluence at 

the end of the subsequent period of extended operation are reviewed for compliance with 

10 CFR 50.61or 10 CFR 50.61a. 

The NRC staff confirms that the applicant has provided sufficient information for PTS for the 

subsequent period of extended operation as follows: 

The applicant identified the neutron fluence at the clad-to-base metal interface for 

each beltline material at the expiration of the subsequent period of extended 

operation. 

There are two methodologies from 10 CFR 50.61 that can be used in the PTS analysis, based on 

the projected neutron fluence at the end of the subsequent period of extended operation. RTNDT is 

the reference temperature (NDT means nil-ductility temperature) used as an indexing parameter 

to determine the fracture toughness and the amount of embrittlement of a material. RTPTS is the 

reference temperature used in the PTS analysis and is related to RTNDT at the end of the facility’s 

operating license. 

The first methodology does not rely on plant-specific surveillance data to calculate delta RTNDT

(∆RTNDT, the mean value of the adjustment or shift in reference temperature caused by 

irradiation). The ∆RTNDT is determined by multiplying a chemistry factor from the tables in 
4.2-9 

10 CFR 50.61 by a neutron fluence factor calculated from the neutron flux using Equation 3 in 

10 CFR 50.61. 

For the surveillance data to be defined as credible, the difference in the predicted values and the 

measured values for ∆RTNDT must be less than 15.6 °C (28 °F) for weld metal components or less 

than 9.4 °C (17 °F) for base metal components. When a credible surveillance data set exists, 

the chemistry factor can be determined from these data in lieu of a value from the table in 

10 CFR 50.61. The standard deviation for the ∆RTNDT used in the margin term assessment 

(e.g., σ∆) of the RTPTS calculations may be reduced from 15.6 °C (28 °F) to 7.8 °C (14 °F) for 

welds or from 9.4 °C (17 °F) to 4.7 °C (8.5 °F) for base metal materials. However, σ∆ need not 

exceed one-half of the RTNDT value used in the RTPTS calculations. 

To confirm that the PTS analysis results in RTPTS values below the screening criteria in 

10 CFR 50.61 at the end of the subsequent period of extended operation, the applicant provides 

the following: 

1. For each beltline material, provide the unirradiated RTNDT, the method of calculating the 

unirradiated RTNDT (either generic or plant-specific), the margin, chemistry factor, the 

method of calculating the chemistry factor, the mean value for the shift in transition 

temperature, and the RTPTS value. 

2. If there are two or more data for a surveillance material that is from the same heat of 

material as the beltline material, provide analyses to determine whether the data are 

credible in accordance with NRC RG 1.99, Revision 2, and whether the margin value 

used in the analysis is appropriate. 

3. If a surveillance program does not include the vessel beltline controlling material but two 

or more data sets are available from other beltline materials, then provide an analysis of 

the data in accordance with NRC RG 1.99, Revision 2, Regulatory Position C.2.1, to 

show that the results either bound or are comparable to the values that would be 

calculated for the same materials using Regulatory Position C.1.1. 

If the PTS screening criteria in 10 CFR 50.61 are projected to be exceeded during the subsequent 

period of extended operation, an analysis based on NRC RG 1.154 (Ref. 16) or 10 CFR 50.61a 

may be submitted for review. For applicants with PTS analysis based upon an NRC-approved 

submittal using 10 CFR 50.61a, the analysis is revised to reflect the subsequent period of 

extended operation. 

4.2.3.1.3.3 10 CFR 54.21(c)(1)(iii) 

The NRC staff reviews the applicant’s proposal to demonstrate that the effects of aging on the 

intended function(s) will be adequately managed for the subsequent period of extended operation 

will be reviewed on a case-by-case basis. 

If corrective actions are necessary, the NRC staff ensures that the SLRA provides an assessment 

of the CLB TLAA for PTS, a discussion of the flux reduction program implemented in accordance 

with § 50.61(b)(3), if necessary, and an identification of the viable options that exist for managing 

the aging effect in the future. As part of this review, the staff ensures that the applicant addressed 

the following topics: 
4.2-10 

A. The applicant explains its core management plans (e.g., operation with a low leakage core 

design and/or integral burnable neutron absorbers) from now through the end of 

the subsequent period of extended operation. Based on this core management strategy, 

the applicant: 

(1) Identifies the material in the RPV which has limiting RTPTS value, 

(2) Provides the projected neutron fluence value for the limiting material at end of the 

subsequent period of extended operation, 

(3) Provides the projected RTPTS value for the limiting material at end of the 

subsequent period of extended operation, and 

(4) Provides the projected date and neutron fluence values at which the limiting 

material will exceed the screening criteria in § 50.61. 

B. The applicant discusses the AMPs or aging management activities that it intends to 

implement, which actively “manage” the condition of the facility’s RPV and hence, the risk 

associated with PTS. This discussion is expected to address, at least, the facility’s reactor 

pressure vessel material surveillance program. 

C. If corrective actions are necessary, the applicant briefly discusses the options that it is 

considering with respect to “resolving” the PTS issue through end of the subsequent 

period of extended operation. It is anticipated that this discussion includes some or all of 

the following: 

(1) Plant modifications (e.g., heating of emergency core cooling system injection 

water) which could limit the risk associated with postulated PTS events [see 

§ 50.61(b)(4) and/or (b)(6)], 

(2) More detailed safety analyses which may be performed to show that the PTS risk 

for the facility is acceptably low through end of the subsequent period of extended 

operation [see § 50.61(b)(4)], 

(3) More advanced material property evaluation (e.g., use of Master Curve 

technology) to demonstrate greater fracture resistance for the limiting material 

[applies to § 50.61(b)(4)], 

(4) The potential for RPV thermal annealing in accordance with § 50.66 

[see § 50.61(b)(7)], and/or 

(5) Use of the alternative PTS Rule (§ 50.61a). 

4.2.3.1.4 Pressure-Temperature Limits 

The regulation in 10 CFR Part 50, Appendix G requires that the RPV be maintained within 

established P-T limits during normal operating conditions of the plant, including heat-ups and 

cool-downs of the reactor and anticipated operational transients, and during pressure test and 

system leak test conditions. These limits specify the maximum allowable pressure as a function 

of reactor coolant temperature. As the RPV becomes embrittled and its fracture toughness is 

reduced, the allowable pressure (given the required minimum temperature) is reduced. 
4.2-11 

The regulation in 10 CFR 50.36 (Ref. 17) requires that P-T limits be controlled by plant TS; 

however, the process for performing updates of the P-T limits depends on whether the P-T limit 

curves for the facility are maintained in the Limiting Conditions of Operation Section of the TS 

(i.e., in the TS LCOs) or in a PTLR that is controlled and updated in accordance with the 

Administrative Controls Section of the plant TS (i.e., by an Administrative Controls TS Section). 

P-T limits are TLAAs for the application if the plant currently has P-T limit curves approved for the 

expiration of the current period of operation (e.g., 32 EFPY or some other licensed EFPY value 

defined for the expiration date of the current license). However, as stated in Standard Review 

Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

(SRP-SLR) Section 4.2.2.1.3, the assessment of P-T limit TLAAs for incoming SLRAs and basis 

for accepting the TLAAs under the requirements of 10 CFR 54.21(c)(1)(i), (ii) or (iii) depends on 

the process that is used for updating the P-T limits. 

For P-T limits that are located in the TS LCOs and are controlled by the 10 CFR 50.90 license 

amendment process, the P-T limits are required to be updated and approved by the NRC prior to 

expiration of the current P-T limit curves in the TS LCOs, or when a change to the P-T limits is 

needed for compliance with the requirements in Section IV.C of 10 CFR Part 50, Appendix H. For 

those plants that have approved PTLRs, the P-T limits are required to be updated prior to 

expiration of the current P-T limit curves in the PTLRs, or when a change to the P-T limits is 

needed for compliance with the requirements in Section IV.C of 10 CFR Part 50, Appendix H, or 

when required by a specific P-T limits update clause in the Administrative Controls TS Section 

that governs implementation of the PTLR process. 

Specifically, for plants with approved PTLRs, the Administrative Controls TS Section governing 

the PTLR process requires that the update of the P-T limits be accomplished using prescribed 

methodologies referenced in the TS requirements. NRC generic letter (GL) 96-03 (Ref. 18) 

provides the NRC’s position on the minimum requirements that need to be included in the 

Administrative Controls TS Section that governs implementation of the PTLR process and the 

type of information that need to be included in the NRC-approved methodologies that will be used 

to update the P-T limits and PTLRs. The GL identifies that 10 CFR 50.90 license amendment 

requests are not necessary for updates of the P-T limit curves if the required methodologies are 

used to update the P-T limits in the PTLRs. Since GL 96-03 establishes the NRC’s position on 

what needs be included within the scope of the P-T limit methodologies, applicants with approved 

PTLRs should verify that the P-T limit methodologies referenced in the applicable Administrative 

Controls TS Section for their PTLR processes are still in conformance with the criteria in 

GL 96-03, and that a resulting 10 CFR 54.22 change of the TS is not needed for their SLRAs. If it 

is determined that a change to the referenced methodologies is needed for the SLRA, the 

applicant should submit the changes to the referenced methodologies as part of a 10 CFR 54.22 

implemented license amendment and TS change request for the SLRA. 

4.2.3.1.4.1 10 CFR 54.21(c)(1)(i) 

If the P-T limits are located in the TS LCOs or the PTLRs (whichever is applicable to CLB) and the 

applicant selects the 10 CFR 54.21(c)(1)(i) option as the basis for accepting the TLAA, the 

projected neutron fluences for the 1⁄4T and 3⁄4T locations of each of the RPV beltline components 

at the end of the subsequent period of extended operation are reviewed to confirm that they are 

bounded by the neutron fluences used to develop the existing P-T limit analysis. 
4.2-12 

4.2.3.1.4.2 10 CFR 54.21(c)(1)(ii) 

The documented results of the revised P-T limit analysis based on the projected reduction in 

fracture toughness at the end of the subsequent period of extended operation is reviewed for 

compliance with 10 CFR Part 50, Appendix G. If the P-T limits are controlled by the TS LCOs, the 

reviewer confirms that the updated P-T limits for the facility are submitted as a 10 CFR 54.22 

required license amendment and TS change request for the facility. The reviewer reviews the 

submitted P-T limit analysis for compliance with requirements in 10 CFR Part 50, Appendix G. If 

the P-T limits are controlled by an applicable Administrative Control TS Section and a PTLR 

process, the updated P-T limits are reviewed to confirm that the updated P-T limits have been 

submitted in an updated PTLR that has been included with the SLRA. The P-T limits in the 

updated PTLR are also reviewed to confirm that the P-T limits have been calculated in 

accordance with the methodologies referenced in the applicable Administrative Controls TS 

Section for the PTLR process, or if not, that the updated methodology or methodologies used to 

generate the updated P-T limits in the PTLR has or have been submitted as part of a 

10 CFR 54.22 implemented license amendment and TS change request for the SLRA. 

The P-T limit evaluations are dependent upon the neutron fluence. 

4.2.3.1.4.3 10 CFR 54.21(c)(1)(iii) 

Updated P-T limits for the subsequent period of extended operation must be established and 

implemented prior to entry into the subsequent period of extended operation. 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 that are administratively amended through a PTLR process can be considered adequate 

AMPs within the scope of 10 CFR 54.21(c)(1)(iii), such that P-T limits will be maintained through 

the subsequent period of extended operation. 

For plants whose P-T limits are controlled by an applicable Administrative Controls TS Section 

and an NRC-approved PTLR process, the methodologies referenced in the applicable TS Section 

are reviewed to verify that they will comply with the requirements in 10 CFR Part 50, Appendix G 

and conform to the recommended position for minimum methodology contents in GL 96-03. 

Otherwise, the methodology bases for generating updates of the P-T limits during the subsequent 

period of extended operation are reviewed to determine whether a 10 CFR 54.22-implemented 

license amendment and TS change of the methodology requirements is necessary for the SLRA. 

For BWRs whose applicants are accepting their P-T limits in accordance with the criterion in 

10 CFR 54.21(c)(1)(iii), the NRC staff confirms that the applicant addresses the following Renewal 

Applicant Action Item in the NRC staff’s Safety Evaluation Report (SER) for BWRVIP-74 (Ref. 19). 

Action Item 9: Appendix A of BWRVIP-74-A (Ref. 20) indicates that a set of P-T 

curves should be developed for the heat-up and cool-down operating conditions 

in the plant at a given EFPY in the subsequent period of extended operation. 

This means that, for this action item, the applicant has not provided updated curves, but shall 

have a procedure for updating P-T limits in accordance with 10 CFR Part 50, Appendix G, that will 

cover 80 years. 
4.2-13 

4.2.3.1.5 Elimination of Boiling Water Reactor Circumferential Weld Inspection 

Some BWRs have an approved technical alternative in the CLB, which eliminates the RPV 

circumferential shell weld inspections from the ASME Code Section XI program for the current 

license term. Approved technical alternatives for SLR have yet to be developed. If these 

analyses are identified as TLAAs, they will be evaluated on a case-by-case basis in accordance 

with 10 CFR 54.21(c)(1). 

4.2.3.1.6 Boiling Water Reactor Axial Welds 

Those BWRs that have been approved to use the circumferential weld technical alternative also 

performed conditional probability of failure analyses of their RPV axial shell welds. Approved 

technical alternatives for SLR have yet to be developed. If these analyses are identified as 

TLAAs, they will be evaluated on a case-by-case basis in accordance with 10 CFR 54.21(c)(1). 

4.2.3.2 Final Safety Analysis Report Supplement 

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 RPV neutron 

embrittlement TLAA. Table 4.2-1, “Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses” of this review plan section contains examples of acceptable FSAR 

Supplement information for this TLAA. The reviewer verifies that the applicant has provided an 

FSAR Supplement with information equivalent to that in Table 4.2-1. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

4.2.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this section and whether the NRC staff’s evaluation supports conclusions of the 

following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

included in the SER: 

On the basis of its review, as discussed above, the NRC staff concludes that 

the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that, for the RPV neutron embrittlement TLAA, [choose 

which is appropriate] 
4.2-14 

(i) the analyses remain valid for the subsequent period of extended 

operation, 

(ii) the analyses have been projected to the end of the subsequent period of 

extended operation, or 

(iii) the effects of aging on the intended function(s) will be adequately 

managed for the subsequent period of extended operation. The NRC 

staff also concludes that the FSAR Supplement contains an appropriate 

summary description of the RPV neutron embrittlement TLAA evaluation 

for the subsequent period of extended operation. 

4.2.5 References 

1. NRC. Regulatory Information Summary (RIS) No. 2014-11, “Information on Licensing 

Applications for Fracture Toughness Requirements for Ferritic Reactor Coolant Pressure 

Boundary Components.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML14149A165. Washington, DC: U.S. Nuclear Regulatory 

Commission. October 14, 2014. 

2. 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

3. 10 CFR 54.21, “Contents of Application–Technical Information.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016. 

4. 10 CFR Part 50, Appendix H, “Reactor Vessel Material Surveillance Program 

Requirements.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

5. NRC. Regulatory Guide 1.190, “Calculational and Dosimetry Methods for Determining 

Pressure Vessel Neutron Fluence.” ADAMS Accession No. ML010890301. 

Washington, DC: U.S. Nuclear Regulatory Commission. 2001. 

6. 10 CFR Part 50, Appendix G, “Fracture Toughness Requirements.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016. 

7. 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

8. 10 CFR 50.61a, “Alternate Fracture Toughness Requirements for Protection Against 

Pressurized Thermal Shock Events.” Washington, DC: U.S. Nuclear Regulatory 

Commission. 2016. 

9. L.A. Reyes. Letter (May 27) to the Commission. ADAMS Accession No. ML041190564. 

Washington, DC: U.S. Nuclear Regulatory Commission. 2004. 

10. 10 CFR 50.90, “Application for Amendment of License, Construction Permit, or Early Site 

Permit.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016. 

11. 10 CFR 54.22, “Contents of Application – Technical Specifications.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016. 
4.2-15 

12. 10 CFR 50.59, “Changes, Tests, and Experiments.” Washington, DC: U.S. Nuclear 

Regulatory Commission. 2016. 

13. NRC. Regulatory Guide 1.99, “Radiation Embrittlement of Reactor Vessel Materials.” 

Revision 2. ADAMS Accession No. ML003740284. Washington, DC: U.S. Nuclear 

Regulatory Commission. May, 1988. 

14. ASME. ASME Code Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components, Nonmandatory Appendix K, Assessment of Reactor Vessels with Low 

Upper Shelf Charpy Impact Energy Levels.” New York, New York: The American Society 

of Mechanical Engineers. 2010. 

15. NRC. NUREG–0800, “U.S. Nuclear Regulatory Commission, Standard Review Plan.” 

ADAMS Accession No. ML070630046. Washington, DC: U.S. Nuclear Regulatory 

Commission. March 2007. 

16. NRC. Regulatory Guide 1.154, “Format and Content of Plant-Specific Pressurized 

Thermal Shock Safety Analysis Reports for Pressurized Water Reactors.” 

Washington, DC: U.S. Nuclear Regulatory Commission. January 1987. 

17. 10 CFR 50.36, “Technical Specifications.” Washington, DC: U.S. Nuclear Regulatory 

Commission. 2016. 

18. NRC. Generic Letter 96-03, “Relocation of the Pressure Temperature Limit Curves and 

Lower Temperature Overpressure Protection System Limits.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 1996. 

19. Christopher Grimes. Letter (October 18) to Carl Terry of Niagara Mohawk Power 

Company, BWRVIP Chairman, “Acceptance for Referencing of EPRI Proprietary Report 

TR-113596, BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection 

and Flaw Evaluation Guidelines BWRVIP-74), and Appendix A, Demonstration of 

Compliance with the Technical Information Requirements of the License Renewal Rule 

(10 CFR 54.21).” Washington, DC: U.S. Nuclear Regulatory Commission. 2001. 

20. EPRI. EPRI TR–1008872, “BWRVIP-74-A, BWR Vessels and Internals Project, BWR 

Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License 

Renewal.” Palo Alto, California: Electric Power Research Institute. June 2003. 

21. 10 CFR 50.71, “Maintenance of Records, Making of Reports.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016. 
4.2-16 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

Neutron Fluence 

Example for acceptance per 

§ 54.21(c)(1)(iii) 

The neutron fluence of each reactor vessel 

component made from a ferritic steel 

material has been projected to the end of 

the period of extended operation using a 

methodology that conforms to the guidance 

in RG 1.190 or other fluence methodology 

approved by the staff. The neutron fluence 

values for these components may be 

monitored through the end of the 

subsequent period of extended operation 

using a program that conforms to the 

guidance in GALL-SLR Report AMP X.M2, 

“Neutron Fluence Monitoring,” or 

alternatively, using a plant-specific program 

that has been approved by the staff. 

Fluence values have 

been projected for the 

subsequent period of 

extended operation and 

provided in the SLRA. 

Upper-shelf energy 

(USE) 

Example for acceptance per 

§ 54.21(c)(1)(ii) 

Example for Plant-Specific USE Analysis 

Accepted Under § 54.21(c)(1)(ii) 

10 CFR Part 50 Appendix G Paragraph 

IV.A.1 requires that the RPV beltline 

materials must have Charpy upper-shelf 

energy (USE) of no less than 68 J (50 ft-lb) 

throughout the life of the reactor pressure 

vessel (RPV) unless otherwise approved by 

the NRC. The USE analyses for the ferritic 

steel components (i.e., RPV shell plates or 

forgings, nozzle plates or forgings, and 

associated pressure retaining welds) in the 

beltline region of the RPV have been 

updated based on component neutron 

fluence values that have been projected to 

the end of the subsequent period of 

extended operation and the current RPV 

surveillance test data for the facility. 

[Applicant to add any additional information 

it considers necessary for the quality of the 

FSAR supplement summary description, 

including information that it may desire to 

include relative to codes, standards, 

regulatory guide criteria, or other NRCapproved methods used in performance of 

the USE calculations.] The updated USE 

values for the components are projected to 

exceed 68 J (50 ft-lb) at the end of the 

subsequent period of extended operation. 

This provides an acceptable basis for 

demonstrating that the USE TLAA is 

acceptable in accordance with the TLAA 

acceptance criterion in 10 CFR 

54.21(c)(1)(ii) and that the analysis has been 

projected to the end of the subsequent 

period of extended operation. 

The updated USE 

analysis is complete. 

That is, the updated USE 

analysis accepted under 

10 CFR 54.21(c)(1)(ii) 

was completed and 

quality assurance 

reviewed by the applicant 

prior to submittal of the 

SLRA and is included in 

the SLRA submitted 

for NRC approval in 

accordance with 

10 CFR Part 54 reporting 

requirements. 

The basis for 

demonstrating 

acceptance of the 

TLAA under 

10 CFR 54.21(c)(1)(ii) is 

included in the SLRA. 
4.2-17 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

Upper-shelf energy 

(USE) 

Example for acceptance per 

§ 54.21(c)(1)(ii) 

Example for Plant-Specific RPV Component 

USE Assessment Projected Under 

§54.21(c)(1)(ii) That Fails to Meet the 50 ft-lb 

(68 J) USE Requirement at the End of the 

Subsequent Period of Extended Operation 

and an EMA is submitted to demonstrate 

acceptability under 10 CFR 54.21(c)(1)(ii) 

The upper shelf energy analysis for RPV 

[Insert specific RPV shell, forging or weld 

component description and ID number along 

with applicable Heat No. in parentheses], as 

projected to the end of the subsequent 

period of extended operation, did not comply 

with the 50 ft-lb (68 J) for these types of 

assessment in 10 CFR Part 50, Appendix G. 

To address the potential non-compliance, a 

plant-specific equivalent margins analysis 

(EMA) for the component was submitted 

[Select Either: “with the LRA” or “in a 

license amendment”] to demonstrate that 

the safety margins against fracture for 

component are at least as conservative as 

those required for the component by the 

provisions in the ASME Boiler and Pressure 

Vessel Code, Section XI, for the facility. The 

EMA was approved [Select Either: “in the 

safety evaluation report for the SLRA.” or “in 

an individual safety evaluation for the license 

amendment action that was submitted in 

accordance with 10 CFR Part 50, 

Appendix G, reporting requirements.”] This 

provides sufficient demonstration that the 

EMA(s) for the RPV component(s) [is/are] 

acceptable in accordance with the 

TLAA acceptance criterion in 

10 CFR 54.21(c)(1)(ii) and that the 

[analysis/analyses] [has/have] been 

projected to the end of the subsequent 

period of extended operation. 

The updated EMA 

analysis is complete. 

That is, the updated 

EMA analysis submitted 

under 10 CFR 

54.21(c)(1)(ii) was to be 

completed and quality 

assurance reviewed by 

the applicant prior to 

submittal of the SLRA 

and to be included in the 

SLRA that is submitted 

for NRC approval in 

accordance with 10 CFR 

Part 54. Alternatively, 

the EMA analysis was 

submitted as a license 

amendment and 

approved by the NRC in 

accordance with 10 CFR 

50.90, and the SLRA 

provides the basis for 

this prior license 

amendment as a 

sufficient demonstration 

that the TLAA is 

acceptable in 

accordance with 

10 CFR 54.21(c)(1)(ii). 

Upper-shelf energy 

(USE) 

Example for acceptance per 

§ 54.21(c)(1)(ii) 

Example for BWR SLRAs that Submit 

Updated BWRVIP-74 Equivalent Margins 

Analyses for Their RPV Components under 

10 CFR 54.21(c)(1)(ii) 

The upper shelf energy (USE) requirements 

in 10 CFR Part 50, Appendix G for the shell 

[Select Either: “plate components” or 

“forging components”], nozzles, and welds 

located in the beltline region of the reactor 

pressure vessel (RPV) have been 

The updated EMA 

analysis is complete. 

That is, the updated 

EMA analysis accepted 

under 10 CFR 

54.21(c)(1)(ii) was 

completed and quality 

assurance reviewed by 

the applicant prior to 

submittal of the SLRA 

and is included in the 
4.2-18 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

addressed through the performance of an 

equivalent margins analyses (EMA) for the 

components, as permitted by the 

10 CFR Part 50, Appendix G, rule. The 

EMAs were calculated using neutron fluence 

values for the components that were 

projected to the end of the subsequent 

period of extended operation. The EMAs 

were performed in accordance with the 

generic criteria for performing these types of 

assessments in Appendix B of EPRI Report 

No. 1008872 (BWRVIP-74-A) and were 

submitted for NRC review in accordance 

with Applicant Action Item No. 10 in the 

NRC safety evaluation for BWRVIP-74-A 

dated October 18, 2001 (ADAMS 

ML012920549). The NRC reviewed the 

updated EMAs for the components and 

found them to be acceptable in accordance 

with NRC’s criteria for accepting these types 

of EMAs, as given in the NRC safety 

evaluation for the BWRVIP-74-A. This 

provides sufficient demonstration that the 

EMAs for the RPV components are 

acceptable in accordance with the TLAA 

acceptance criterion in 

10 CFR 54.21(c)(1)(ii) and that the analyses 

have been projected to the end of the 

subsequent period of extended operation. 

SLRA submitted for NRC 

approval in accordance 

with 10 CFR Part 54. 

Alternatively, the EMA 

analysis was submitted 

as a license amendment 

and approved by the 

NRC in accordance with 

10 CFR 50.90, and the 

SLRA provides the basis 

for this prior license 

amendment as a 

sufficient demonstration 

that the TLAA is 

acceptable in 

accordance with 

10 CFR 54.21(c)(1)(ii). 

Submittal of these types 

of EMAs are subject to 

the Applicant Action 

Item 10 in the staff’s SE 

for BWRVIP-74-A, dated 

October 18, 2001. 
4.2-19 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

Pressurized thermal shock 

(for PWRs) 

Example for acceptance per 

§ 54.21(c)(1)(ii) 

For PWRs, 10 CFR 50.61 requires the 

reference temperature RTPTS for RPV 

beltline materials to be less than the PTS 

screening criteria at the expiration date of 

the operating license unless otherwise 

approved by the NRC. The reference 

temperature has been determined to be less 

than the PTS screening criteria at the end of 

the subsequent period of extended 

operation, unless alternate requirements 

have been invoked in accordance with 

10 CFR 50.61(b) and approved by the NRC. 

The 10 CFR 50.61 

evaluation is complete. 

Updated PTS analysis 

accepted under 

10 CFR 54.21(c)(1)(ii) to 

be completed and QA’d 

by the applicant prior to 

submittal of the SLRA 

and to be included in the 

SLRA that is submitted 

for NRC approval in 

accordance with 

10 CFR Part 54, and 

the applicant is to 

demonstrate 

acceptability of the TLAA 

during the SLRA review 

using the TLAA 

acceptance criteria in 

10 CFR 54.21(c)(1)(ii). 

Pressure-temperature (P-T) 

limits 

Example for acceptance per 

§ 54.21(c)(1)(iii) 

10 CFR Part 50 Appendix G requires that 

heat-ups and cool-downs of the reactor 

pressure vessel (RPV) be accomplished 

within established P T limits. These limits 

specify the maximum allowable pressure as 

a function of reactor coolant temperature. 

As the RPV becomes embrittled and its 

fracture toughness is reduced, the minimum 

allowable temperature for operating at a 

given reactor pressure in the pressure range 

for permissible operations (i.e., pressures up 

to the maximum allowable safety limit 

pressure set in technical specifications) 

allowable pressure is increased. 

10 CFR Part 50 Appendix G requires 

periodic update of P-T limits based on 

projected embrittlement and data from a 

material surveillance program. The P-T 

limits will be updated in accordance with 

the requirements [Select Either: “the 

10 CFR 50.90 license amendment process.” 

for facilities with P-T limits set and governed 

by the limiting conditions of operation in the 

plant technical specifications, or “the plant’s 

program for implementing its pressuretemperature limits report process, as 

governed by the administrative controls 

section of the plant technical specifications.” 

For P-T limits controlled 

by TS LCOs: Updates of 

the P-T limit curves are 

set relative to the 

expiration dates of the 

existing licensed P-T limit 

curves. Updates of the 

P-T limit curves are to be 

submitted for NRC 

approval in accordance 

with the applicant’s 

10 CFR 50.90 license 

amendment request 

process. Updates of the 

P-T curves must be 

finalized, QA’d, 

submitted for NRC 

approval, approved by 

the NRC, and 

implemented prior to the 

expiration dates of the 

current licensed P-T limit 

curves located in 

the limiting conditions of 

operations section of 

the plant technical 

specifications. 
4.2-20 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

for plants licensed to implement PTLRs] in 

order to consider the impacts of increasing 

neutron fluence levels caused by operations 

during the subsequent period of extended 

operation. 

For P-T limits controlled 

by TS PTLR 

requirements: Updates 

of the P-T limit curves 

are set relative to the 

expiration dates of the 

existing licensed P-T limit 

curves. The updated PT limit curves and 

pressure temperature 

limits report (PTLR) are 

required to be updated in 

accordance with the 

applicant’s PTLR 

implementation process, 

as governed by 

applicable requirements 

in the administrative 

controls section of the 

plant technical 

specifications (TS). 

Updates of the P-T 

curves must be finalized 

and implemented prior to 

the expiration dates of 

the licensed curves in the 

current PTLR. Updated 

PTLRs are to be 

submitted to the NRC in 

accordance with any 

applicable reporting 

requirements in the TS 

administrative controls 

section governing 

implementation of the 

PTLR process 

(depending in the TS 

provisions, this may or 

may not require NRC 

approval). 

Elimination of BWR 

circumferential weld 

inspections and analysis of 

BWR axial welds 

Examples of the FSAR Supplements for 

these TLAAs are not given - approved 

technical alternatives for SLR have yet to be 

developed. 

If the TLAA is applicable, 

a plant-specific 

implementation schedule 

to be provided on a 

plant-specific basis and 

justified by the applicant. 

Other miscellaneous TLAAs 

on RV neutron embrittlement 

Provide sufficient information on how the 

calculations for plant-specific TLAAs were 

performed, what the limiting TLAA 

parameter was calculated to be in 

If the TLAA is applicable, 

a plant-specific 

implementation schedule 

to be provided on a 
4.2-21 

Table 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

accordance with the neutron fluence 

projected for the subsequent period of 

extended operation, and why the TLAA is 

acceptable under either 

10 CFR 54.21 (c)(1)(i), (ii), or (iii). 

plant-specific basis and 

justified by the applicant. 

*An applicant should incorporate the implementation schedule into its FSAR. The reviewer should verify that the 

applicant has identified and committed in the SLRA to any future aging management activities, including 

enhancements and commitments, to be completed before entering the subsequent period of extended operation. The 

NRC staff expects to impose a license condition on any renewed license to ensure that the applicant will complete 

these activities no later than the committed date. 

4.3-1 

4.3 Metal Fatigue 

Review Responsibilities 

Primary—Branch(es) responsible for the time-limited aging analysis (TLAA) issues 

Secondary—None 

4.3.1 Area of Review 

Fatigue occurs in a metal component when it is subjected to fluctuating loads. If the loading is of 

sufficient magnitude or frequency, cracks may initiate and propagate in the component at the 

location of maximum loading. To address fatigue concerns, Section III of the American Society of 

Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) requires a fatigue analysis 

for Class 1 components. The analysis must consider all expected cyclic loads based on the 

anticipated number of cyclic loadings. In the most rigorous evaluation, the ASME Code provisions 

include the calculation of the cumulative usage factor (CUF) for selected locations within a 

component, which is a calculated measure of the expended fatigue initiation life at each location in 

the component. Under these provisions, the ASME Code limits the CUF to a value of less than or 

equal to unity for acceptable fatigue design. A CUF below a value of unity provides assurance 

that no crack has initiated at the analyzed location in the component. Other provisions in 

Section III of the ASME Code allow less rigorous treatment to address the fatigue design in 

components that have smaller or less frequent cyclic loadings, (i.e., fatigue waiver evaluation). In 

some cases, continued adequacy of the fatigue life of a component may be demonstrated through 

reinspections that continue to demonstrate an absence of fatigue flaws, (i.e., as supported by 

applicable flaw tolerance evaluations). In other cases, the growth of fatigue flaws is assessed to 

ensure that flaws detected in components remain within allowable limits. 

The acceptability of metal components from a fatigue standpoint is demonstrated by one or 

more relevant fatigue parameters, which include, but are not limited to, the CUF values, the 

environmentally-adjusted CUFen values, transient cycle limits, and predicted flaw sizes (for fatigue 

flaw tolerance or component flaw evaluations). The limits of the fatigue parameters are 

established by the applicable fatigue analyses and may be a design limit, for example from an 

ASME Code fatigue evaluation, or an analysis-specific value, for example based on the number of 

cyclic load occurrences assumed in fatigue waiver evaluations or the acceptable flaw sizes 

postulated in flaw tolerance or component flaw evaluations. 

As a result of the assumptions used in the underlying evaluations associated with metal 

component fatigue parameters (i.e., the magnitude and frequency of the assumed cyclic loadings 

for the future operating life of the component), the continued validity of metal fatigue analyses is 

reviewed for the subsequent period of extended operation. 

Areas of review to ensure that the metal component fatigue parameter evaluations are valid for 

the subsequent period of extended operation include: 

1. CUF calculations or fatigue waiver evaluations for components designed using the 

fatigue requirements of Section III of the ASME Code or other Codes that use a It

calculation (e.g., the 1969 edition of American National Standards Institute (ANSI) B31.7 

for Class 1 piping, ASME NC-3200 vessels, ASME NE-3200 Class MC components, 

ASME NG-3200 core support structures, and metal bellows designed to ASME 
4.3-2 

NC 3649.4(e)(3), ND-3649.4(e)(3), or NE-3366.2(e)(3) or the Draft ASME Code for 

Pumps and Valves for It analyses). 

2. Fatigue-based maximum allowable stress calculations for components evaluated to 

United States of America Standards (USAS) ANSI B31.1 or ASME Code Class 2 and 3 

requirements. 

3. CUF calculations for components that require evaluation of environmental effects 

(CUFen). 

4. Fatigue-based flaw growth, flaw tolerance, or fracture mechanics analyses, including 

those used to support reinspection intervals for components. 

4.3.2 Acceptance Criteria 

Acceptance criteria are provided in the following subsections for the areas of review described in 

Subsection 4.3.1 that delineate acceptable methods for meeting the requirements of the 

U.S. Nuclear Regulatory Commission (NRC) regulations in Title 10 of the Code of Federal 

Regulations (10 CFR) 54.21(c)(1). 

4.3.2.1 Time-Limited Aging Analysis 

Pursuant to 10 CFR 54.21(c)(1)(i) through (iii), an applicant must demonstrate one of the following 

for each analysis: 

i. The analyses remain valid for the period of extended operation; 

ii. The analyses have been projected to the end of the period of extended operation; or 

iii. The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation. 

In some instances, the applicant may identify activities to be performed to verify the assumption 

bases of the fatigue analyses. Evaluations of those activities are provided by the applicant. The 

reviewer assures that the applicant’s activities are sufficient to confirm the calculation assumptions 

for the subsequent period of extended operation. 

Specific acceptance criteria for metal component fatigue evaluations are discussed in the 

following subsections. 

4.3.2.1.1 Components Evaluated for Fatigue Parameters Other than CUFen

For metal components evaluated for fatigue parameters other than CUFen, the acceptance criteria 

depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are as follows: 

4.3.2.1.1.1 10 CFR 54.21(c)(1)(i) 

The existing fatigue parameter calculations remain valid for the subsequent period of extended 

operation because the number of accumulated cycles and the assumed severity of each of the 

cyclic loadings evaluated in the calculations are not projected to exceed the limits evaluated for 

these loadings. The revised projections are verified to be consistent with historical plant operating 

characteristics and anticipated future operation. 
4.3-3 

4.3.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

The fatigue parameter calculations are revised and shown to remain acceptable throughout the 

subsequent period of extended operation based on a revised projection of the cumulative number 

and assumed severity of each of the cyclic loadings to the end of the subsequent period of 

extended operation. The revised projections are verified to be consistent with historical plant 

operating characteristics and anticipated future operation. The resulting fatigue parameter values 

are verified to remain less than or equal to their respective allowable value for the subsequent 

period of extended operation. 

4.3.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

The applicant proposes an aging management program (AMP) as the basis for demonstrating that 

the effect or effects of aging on the intended function(s) of the structure(s) or component(s) in the 

fatigue parameter evaluations will be adequately managed during the subsequent period of 

extended operation. The AMP in Section X.M1, “Fatigue Monitoring,” of the Generic Aging 

Lessons Learned for Subsequent License Renewal (GALL-SLR) Report provides one method that 

may be used to demonstrate compliance with the requirement in 10 CFR 54.21(c)(1)(iii). 

An applicant may also propose another AMP to demonstrate compliance with the requirement in 

10 CFR 54.21(c)(1)(iii). If the basis for aging management is a plant-specific AMP, the AMP is 

described in terms of the 10 program elements defined in the Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR), Appendix A.1, 

“Branch Technical Position, Aging Management Review—Generic,” Sections A.1.2.3.1 

through A.1.2.3.10. 

If an inspection program is proposed as the basis for aging management, the applicant should 

ensure that (a) inspections will be performed for the specific component(s) or structure(s) in the 

evaluation and (b) applicant has justified that the inspection methods and frequencies in the 

proposed inspection program are applicable to the component(s), such that they may be used to 

demonstrate compliance with the requirement in 10 CFR 54.21(c)(1)(iii). 

4.3.2.1.2 Components Evaluated for CUFen

For metal components evaluated for CUFen, the acceptance criteria depend on the applicant’s 

choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

Applicants should also include CUFen calculations for additional component locations if they are 

considered to be more limiting than those previously evaluated. This sample set includes the 

locations identified in NUREG/CR–6260 and additional plant-specific component locations in the 

reactor coolant pressure boundary if they may be more limiting than those considered in 

NUREG/CR–6260. Plant-specific justification can be provided to demonstrate that calculations for 

the NUREG/CR–6260 locations do not need to be included. Environmental effects on fatigue for 

these critical components can be evaluated using the positions described in Regulatory Guide 

(RG) 1.207, Revision 14; NUREG/CR–6909, Revision 0 (with “average temperature” used 

consistent with the clarification that was added to NUREG/CR–6909, Revision 1); or other 

subsequent NRC-endorsed alternatives. 

 

4 If and when published as RG 1.207, Revision 1 Final. 
4.3-4 

4.3.2.1.2.1 10 CFR 54.21(c)(1)(i) 

The existing CUFen calculations remain valid for the subsequent period of extended operation 

because the number of accumulated cycles, the assumed severity of the cyclic loadings, and the 

assumed water chemistry conditions evaluated in the calculations are not projected to exceed the 

limits evaluated for these parameters. The revised projections for the number of accumulated 

cycles are verified to be consistent with historical plant operating characteristics and anticipated 

future operation. 

A plant-specific justification can be provided to demonstrate that existing CUFen calculations 

performed using guidance in Section 4.3.2.1.3 of NUREG–1800, Revision 2 will remain valid for 

the subsequent period of extended operation and are sufficiently conservative when compared to 

those CUFen calculations that would be generated using the guidance in RG 1.207, Revision 15, 

or in NUREG/CR–6909, Revision 0 (with “average temperature” used consistent with the 

clarification that was added to NUREG/CR–6909, Revision 1). 

4.3.2.1.2.2 10 CFR 54.21(c)(1)(ii) 

The CUFen calculations are revised and shown to remain acceptable throughout the subsequent 

period of extended operation based on a revised projection of the cumulative number of 

occurrences, the assumed severity of cyclic loadings, and the assumed water chemistry 

conditions to the end of the subsequent period of extended operation. The revised projections are 

verified to be consistent with historical plant operating characteristics and anticipated future 

operation. The resulting CUFen values are verified to remain less than or equal to unity for the 

subsequent period of extended operation. 

4.3.2.1.2.3 10 CFR 54.21(c)(1)(iii) 

In Section X.M1 of the GALL-SLR Report, the NRC staff evaluated a program for monitoring and 

tracking the number of occurrences and the severity of critical cyclic loadings for selected 

components. In Section XI.M2 of the GALL-SLR Report, the NRC staff evaluated a program for 

monitoring and tracking water chemistry conditions. The NRC staff determined that these 

programs, when used together, are acceptable AMPs to address the effects of reactor water 

environment on component fatigue life according to 10 CFR 54.21(c)(1)(iii). The GALL-SLR 

Report may be referenced in a subsequent license renewal application and should be treated in 

the same manner as an approved topical report. In referencing the GALL-SLR Report, the 

applicant should indicate that the material referenced is applicable to the specific plant involved 

and should provide the information necessary to adopt the finding of program acceptability as 

described and evaluated in the report. The applicant also should verify that the approvals set 

forth in the GALL-SLR Report for the generic program apply to the applicant’s program. 

Alternatively, the components could be replaced and the CUFen values for the replacement 

components shown to be acceptable for the subsequent period of extended operation. 

4.3.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

 

5 If and when published as RG 1.207, Revision 1 Final. 
4.3-5 

should contain sufficient information such as source of the data, references to the methodology 

used, and parameters used. The basis for demonstrating acceptance of the TLAA under 

10 CFR 54.21(c)(1)(i), (ii), or (iii), should be included and demonstrated in the SLRA. 

4.3.3 Review Procedures 

Review procedures for metal component fatigue parameter evaluations for the areas of review 

described in Subsection 4.3.1 are discussed in the following subsections. 

4.3.3.1 Time-Limited Aging Analysis 

The Code of Record should be used for the re-evaluation, or the applicant may update to a later 

Code edition pursuant to 10 CFR 50.55a using an appropriate Code reconciliation. In the latter 

case, the reviewer verifies that the requirements in 10 CFR 50.55a are met. The reviewer 

assures that the applicant’s activities are sufficient to confirm the calculation assumptions for the 

subsequent period of extended operation. 

4.3.3.1.1 Components Evaluated for Fatigue Parameters Other Than CUFen

For metal components evaluated for fatigue parameters other than CUFen, the review procedures 

depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are as follows: 

4.3.3.1.1.1 10 CFR 54.21(c)(1)(i) 

The operating cyclic load experience and a list of the assumed transients used in the existing 

fatigue parameter calculations are reviewed for the current operating term to ensure that the 

projected number of transient occurrences during the subsequent period of extended operation 

will not exceed the assumed number of transient occurrences in the existing fatigue parameter 

calculations. The projected number of occurrences for each transient is verified to be consistent 

with historical plant operating characteristics and anticipated future operation. In addition, a 

comparison of the operating cyclic load severity to the severity for each transient assumed in the 

existing fatigue parameter calculations is made to demonstrate that the cyclic load severity for 

each transient used in the fatigue parameter calculations remains bounding. For consistency 

purposes, the review also includes an assessment of the TLAA information against relevant 

design basis information and current licensing basis (CLB) information. 

4.3.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

The operating cyclic load experience is reviewed to ensure that the increased number of cyclic 

load occurrences and their severity for each transient used for any reanalysis remain within the 

number of transient occurrences and severity for each transient projected to the end of the 

subsequent period of extended operation. The revised fatigue parameter calculations are 

reviewed to ensure that the fatigue parameter remains less than or equal to the allowed value at 

the end of the subsequent period of extended operation. The revised fatigue parameter 

calculations are shown to remain acceptable based on revised projections of the cumulative 

number of occurrences and the assumed severity of each transient to the end of the subsequent 

period of extended operation. The revised projections are verified to be consistent with historical 

plant operating characteristics and anticipated future operation. For consistency purposes, the 

review also includes an assessment of the TLAA information against relevant design basis 

information and CLB information. 
4.3-6 

4.3.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant proposes an AMP or aging management 

activities as the basis for demonstrating that the effect or effects of aging on the intended 

function(s) of the structure(s) or component(s) in the fatigue parameter evaluation will be 

adequately managed during the subsequent period of extended operation. If Section X.M1, 

“Fatigue Monitoring,” of the GALL-SLR Report is used as the basis for managing cumulative 

fatigue damage or cracking due to fatigue or cyclical loading in the structure(s) or component(s), 

the reviewer reviews the applicant’s AMP against the program elements defined in GALL-SLR 

Report Section X.M1. 

An applicant also has the option of proposing another GALL-based AMP, a plant-specific AMP, or 

plant-specific activities, or combination of, to demonstrate compliance with the requirement in 

10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

management, the reviewer reviews the applicant’s AMP against the program element criteria 

defined in the applicable AMP section in Chapter XI of the GALL-SLR Report. If the basis for 

aging management is a plant-specific AMP or plant-specific aging management activities, the 

reviewer reviews the program element criteria for the AMP or activities against the program 

element criteria defined in this SRP-SLR, Appendix A.1, “Branch Technical Position, Aging 

Management Review—Generic,” Sections A.1.2.3.1 through A.1.2.3.10. 

If a sampling based inspection program (a type of condition monitoring program) is proposed as 

the basis for aging management, the reviewer ensures that the AMP actually performs inspections 

of the specific component(s) or structure(s) in the evaluation at each unit in a multiunit site and 

that the applicant has appropriately justified that the inspection methods and associated 

frequencies are capable of managing cumulative fatigue damage or cracking by fatigue or cyclical 

loading in the component(s) or structure(s), such that the TLAA may be accepted in accordance 

with 10 CFR 54.21(c)(1)(iii). 

4.3.3.1.2 Components Evaluated for CUFen

For metal components evaluated for CUFen, the review procedures depend on the applicant’s 

choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

Applicants should include CUFen calculations for the limiting component locations exposed to the 

reactor water environment. This sample set includes the locations identified in NUREG/CR–6260 

and additional plant-specific component locations in the reactor coolant pressure boundary if they 

may be more limiting than those considered in NUREG/CR–6260. Plant-specific justification can 

be provided to demonstrate that calculations for the NUREG/CR–6260 locations do not need to 

be included. Environmental effects on fatigue for these critical components may be evaluated 

using the guidance in RG 1.207, Revision 16; NUREG/CR–6909, Revision 0 (with “average 

temperature” used consistent with the clarification that was added to NUREG/CR–6909, 

Revision 1); or other subsequent NRC-endorsed alternatives. 

4.3.3.1.2.1 10 CFR 54.21(c)(1)(i) 

The operating cyclic load experience and a list of the assumed transients used in the existing 

fatigue parameter calculations are reviewed for the current operating term to ensure that the 

 

6 If and when published as RG 1.207, Revision 1 Final. 
4.3-7 

number of assumed occurrences of each transient would not be exceeded during the subsequent 

period of extended operation. A comparison of the operating cyclic load severity to the severity 

assumed in the existing fatigue parameter calculations for each transient should be made to 

demonstrate that the cyclic load severities used in the fatigue parameter calculations remain 

bounding. In addition, a comparison of the water chemistry conditions to those assumed in the 

existing environmental multiplier (Fen) calculations should be made to demonstrate that the water 

chemistry conditions used in the Fen calculations remain appropriate. For consistency purposes, 

the review also includes an assessment of the TLAA information against relevant design basis 

information and CLB information. A plant-specific justification can be provided to demonstrate 

that the guidance in Section 4.3.2.1.3 of NUREG–1800, Revision 2, is applicable to the existing 

CUFen calculations. Considering the evaluations above, verify the existing CUFen calculations 

remain valid for the subsequent period of extended operation. 

4.3.3.1.2.2 10 CFR 54.21(c)(1)(ii) 

The operating cyclic load experience and a list of the assumed transients used in the existing 

fatigue parameter calculations is reviewed for the current operating term to ensure that the 

number of assumed occurrences for each transient are projected to the end of the subsequent 

period of extended operation. The reviewer verifies that a comparison of the operating cyclic load 

severity to the severity assumed in the existing fatigue parameter calculations for each transient 

has been made to demonstrate that the cyclic load severities used in the fatigue parameter 

calculations remain bounding. In addition, the reviewer verifies that a comparison of the water 

chemistry conditions to those assumed in the Fen calculations has been made to demonstrate that 

the water chemistry conditions used in the Fen calculations are appropriate. For consistency 

purposes, the review also includes an assessment of the TLAA information against relevant 

design basis information and CLB information. The review includes verification that the applicant 

has updated the CUFen calculations for the applicable NUREG/CR–6260 or more limiting 

component locations using the methods of analysis in either RG 1.207, Revision 16, 

NUREG/CR–6909, Revision 0 (with “average temperature” used consistent with the clarification 

that was added to NUREG/CR–6909, Revision 1); or other subsequent NRC-endorsed 

alternatives. 

The Code of Record should be used for the reevaluation, or the applicant may update to a later 

Code edition pursuant to 10 CFR 50.55a using an appropriate Code reconciliation. In the latter 

case, the reviewer verifies that the requirements in 10 CFR 50.55a are met. 

4.3.3.1.2.3 10 CFR 54.21(c)(1)(iii) 

The applicant may reference Sections X.M1 and XI.M2 of the GALL-SLR Report in its subsequent 

license renewal application and use these GALL-SLR chapters to accept the TLAA in accordance 

with 10 CFR 54.21(c)(1)(iii), as appropriate. The review should verify that the applicant has stated 

that the report is applicable to its plant with respect to its program that monitors and tracks the 

number and severity of critical cyclic loadings and water chemistry conditions for metal 

components. The reviewer verifies that the applicant has identified the appropriate programs as 

described and evaluated in the GALL-SLR Report. The reviewer also ensures that the applicant 

has stated that its program contains the same program elements that the NRC staff evaluated and 

relied upon in approving the corresponding generic program in the GALL-SLR Report. For 

consistency purposes, the review also includes an assessment of the TLAA information against 

relevant design basis and CLB information (including applicable cycle-counting requirements and 

water chemistry monitoring set forth in the applicable AMPs). 
4.3-8 

An applicant also has the option of proposing another GALL-based AMP, a plant-specific AMP, or 

plant-specific activities, or combination of, to demonstrate compliance with the requirement in 

10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

management, the reviewer reviews the applicant’s AMP against the program element criteria 

defined in the applicable AMP section in Chapter XI of the GALL-SLR Report. If the basis for 

aging management is a plant-specific AMP or plant-specific aging management activities, the 

reviewer reviews the program element criteria for the AMP or activities against the program 

element criteria defined in this SRP-SLR, Appendix A.1, “Branch Technical Position, Aging 

Management Review—Generic,” Sections A.1.2.3.1 through A.1.2.3.10. 

If a sampling based inspection program (a type of condition monitoring program) is proposed as 

the basis for aging management, the reviewer ensures that the AMP actually performs inspections 

of the specific component(s) or structure(s) in the evaluation at each unit in a multiunit site and 

that the applicant has appropriately justified that the inspection methods and associated 

frequencies are capable of managing cumulative fatigue damage or cracking by fatigue or cyclical 

loading in the component(s) or structure(s), such that the TLAA may be accepted in accordance 

with 10 CFR 54.21(c)(1)(iii). 

4.3.3.2 Final Safety Analysis Report Supplement 

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. 

Table 4.3-1 contains examples of acceptable FSAR Supplement information for fatigue parameter 

TLAAs that are dispositioned in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii). The reviewer 

verifies that the applicant has provided a FSAR Supplement with information equivalent to that in 

Table 4.3-1. The table includes examples for environmentally-assisted fatigue parameter TLAAs 

and non-environmentally-assisted fatigue parameter TLAAs. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

4.3.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this section and whether the NRC staff’s evaluation supports conclusions of the 

following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

included in the NRC staff’s Safety Evaluation Report: 
4.3-9 

On the basis of its review, as discussed above, the NRC staff concludes that 

the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that, for the [reviewer to insert applicable type of metal 

fatigue analysis] TLAA, [choose which is appropriate] 

(i) the analyses remain valid for the subsequent period of extended 

operation, 

(ii) the analyses have been projected to the end of the subsequent period of 

extended operation, or 

(iii) the effects of aging on the intended function(s) will be adequately 

managed for the subsequent period of extended operation. The NRC 

staff also concludes that the FSAR Supplement contains an appropriate 

summary description of the [reviewer to insert applicable type of metal 

fatigue analysis] TLAA, evaluation for the subsequent period of extended 

operation. 

4.3.5 References 

1. ANSI/ASME B31.1, “Power Piping.” New York, New York: American National 

Standards Institute. 

2. ANSI/ASME B31.7-1969, “Nuclear Power Piping.” New York, New York: American 

National Standards Institute. 

3. NRC. Regulatory Guide 1.207, “Guidelines for Evaluating the Effects of Light-Water 

Reactor Coolant Environments in Fatigue Analyses of Metal Components.” Revision 17. 

Washington, DC: U.S. Nuclear Regulatory Commission. 

4. NRC. NUREG/CR–6909, Revision 1, ANL–12/60, “Effect of LWR Coolant Environments 

on the Fatigue Life of Reactor Materials.” Agencywide Documents Access and 

Management System (ADAMS) Accession No. ML14087A068. Washington, DC: 

U.S. Nuclear Regulatory Commission. March 2014. 

5. ASME. ASME Code, Section III, “Rules for Construction of Nuclear Facility Components.” 

New York, New York: The American Society of Mechanical Engineers. 

6. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components, Nonmandatory, Appendix A, Analysis of Flaws.” New York, New York: The 

American Society of Mechanical Engineers. 

7. ASME. ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

Components, Appendix C, Evaluation of Flaws in Austenitic Piping.” New York, New York: 

The American Society of Mechanical Engineers. 

 

7 If and when published as RG 1.207, Revision 1 Final. 
4.3-10 

8. NRC. NUREG/CR–5704, “Effects of LWR Coolant Environments on Fatigue Design 

Curves of Austenitic Stainless Steels.” ADAMS Accession No. 9904280060. 

Washington, DC: U.S. Nuclear Regulatory Commission. April 1999. 

9. NRC. NUREG/CR–6583,” Effects of LWR Coolant Environments on Fatigue Design 

Curves of Carbon and Low-Alloy Steels.” ADAMS Accession No. 9803260384. 

Washington, DC: U.S. Nuclear Regulatory Commission. March 1998. 

10. NRC. NUREG/CR–6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to 

Selected Nuclear Power Plant Components.” ADAMS Accession No. 9503280383. 

Washington, DC: U.S. Nuclear Regulatory Commission. March 1995. 

 
4.3-11 

Table 4.3-1 Examples of FSAR Supplement for Metal Fatigue TLAA Evaluation 

TLAA Description of Evaluation Implementation

Schedule*

10 CFR 54.21(c)(1)(i) Examples 

Components 

Evaluated for 

Fatigue 

Parameters 

Other than 

CUFen 

[Applicant to identify and provide adequate description of the 

specific metal fatigue parameter evaluation] 

The number of occurrences and severity of each of the thermal 

and pressure transients, projected to the end of the subsequent 

license renewal operating period, demonstrate that the 

[Applicant to insert Name of the TLAA] remains valid during the 

subsequent license renewal operating period and therefore, that 

this TLAA is acceptable in accordance with the criterion in 

10 CFR 54.21(c)(1)(i). 

Completed prior to a 

submittal of an SLRA 

Components 

Evaluated for 

CUFen 

[Applicant to identify and provide adequate description of the 

specific metal fatigue evaluation for evaluating environmentally 

assisted fatigue in ASME Code Class 1 or Safety Class 1 

components] 

The effects of the water environment on component fatigue life 

have been addressed by assessing the impact of the water 

environment on the limiting component locations. [Applicant to 

provide adequate description of its plant-specific justification 

demonstrates that the guidance in Section 4.3.2.1.3 of 

NUREG–1800, Revision 2 applies to the existing CUFen 

calculations.] 

The number of occurrences and severity of each of the thermal 

and pressure transients, projected to the end of the subsequent 

license renewal operating period, and consideration of the 

water chemistry parameters demonstrate that the TLAA on 

environmentally assisted fatigue remains valid during the 

subsequent license renewal operating period and therefore, 

that this TLAA is acceptable in accordance with 

10 CFR 54.21(c)(1)(i). 

Completed prior to a 

submittal of an SLRA 

10 CFR 54.21(c)(1)(ii) Examples 

Components 

Evaluated for 

Fatigue 

Parameters 

Other than 

CUFen 

[Applicant to identify and provide adequate description of the 

specific metal fatigue parameter evaluation] 

The analysis has been projected to the end of the subsequent 

license renewal operating period, considering the number of 

occurrences and severity of each of the thermal and pressure 

transients, and demonstrates that the TLAA is acceptable in 

accordance with 10 CFR 54.21(c)(1)(ii). 

Completed prior to a 

submittal of an SLRA 

Components 

Evaluated for 

CUFen 

[Applicant to identify and provide adequate description of the 

specific metal fatigue evaluation for evaluating environmentally 

assisted fatigue in ASME Code Class 1 or Safety Class 1 

components] 

The effects of the water environment on component fatigue life 

have been addressed by assessing the impact of the water 

environment on the limiting component locations, using the 

positions described in Regulatory Guide 1.207, Revision 1†; 

NUREG/CR-6909, Revision 0 (with “average temperature” 

used consistent with the clarification that was added to 

Completed prior to a 

submittal of an SLRA 
4.3-12 

Table 4.3-1 Examples of FSAR Supplement for Metal Fatigue TLAA Evaluation 

TLAA Description of Evaluation Implementation

Schedule*

NUREG/CR-6909, Revision 1); or other subsequent 

NRC-endorsed alternatives. 

The analysis for environmentally-assisted fatigue has been 

projected to the end of the subsequent license renewal operating 

period, considering the number of occurrences and severity of 

each of the thermal and pressure transients and the water 

chemistry parameters, and demonstrates that the TLAA is 

acceptable in accordance with 10 CFR 54.21(c)(1)(ii). 

10 CFR 54.21(c)(1)(iii) Examples 

Components 

Evaluated for 

Fatigue 

Parameters 

Other than 

CUFen

Fatigue evaluations were performed to ensure the continued 

validity of the metal fatigue analyses for the subsequent period 

of extended operation. 

[Applicant to provide adequate description of the specific metal 

fatigue parameter evaluation] 

The fatigue monitoring program is being used as the 

basis for accepting these TLAAs in accordance with 

10 CFR 54.21(c)(1)(iii). The AMP is for accepting these TLAAs 

in accordance with 10 CFR 54.21(c)(1)(iii). The AMP The AMP 

monitors and tracks the number of occurrences and severity of 

thermal and pressure transients, and requires corrective actions 

to ensure that applicable fatigue analyses remain within their 

allowable limits. The effects of aging due to fatigue will be 

managed by the AMP for the subsequent period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(iii). 

(If the applicant will be 

using the Fatigue 

Monitoring Program to 

accept the TLAA. This 

FSAR supplement 

would not apply for an 

applicant that is 

accepting the fatigue 

TLAA using an AMP 

different than the 

Fatigue Monitoring 

Program.) 

In order to justify 

continued acceptance 

of the TLAA under 

10 CFR 54.21(c)(1)(iii), 

the existing fatigue 

monitoring program will 

continue to be 

implemented during the 

subsequent period of 

extended operation. 

Any SLR 

enhancements of the 

program needed for 

aging management and 

acceptance of the 

TLAA are to be 

incorporated and 

implemented into the 

program at least 

6 months prior to entry 

into the subsequent 

period of extended 

operation. 

Components 

Evaluated for 

CUFen 

The effects of the water environment on component fatigue life 

will be addressed by assessing the impact of the water 

environment on the limiting component locations, using the 

positions described in Regulatory Guide 1.207, Revision 1†; 

NUREG/CR–6909, Revision 0 (with “average temperature” 

used consistent with the clarification that was added to 

NUREG/CR–6909, Revision 1); or other subsequent 

In order to justify 

continued acceptance of 

the TLAA under 

10 CFR 54.21(c)(1)(iii), 

the existing fatigue 

monitoring program will 

continue to be 
4.3-13 

Table 4.3-1 Examples of FSAR Supplement for Metal Fatigue TLAA Evaluation 

TLAA Description of Evaluation Implementation

Schedule*

NRC-endorsed alternatives. A limiting sample of critical 

components can be evaluated by applying environmental 

adjustment factors to the existing CUF analyses or by performing 

more refined calculations. 

The AMPs monitor and track the number of occurrences and 

severity of thermal and pressure transients, monitor water 

chemistry, and require corrective actions to ensure that the 

applicable fatigue analyses remain within their allowable limits. 

The effects of aging due to environmentally assisted fatigue will 

be managed by the AMPs for the subsequent license renewal 

operating period in accordance with 10 CFR 54.21(c)(1)(iii). 

implemented during the 

subsequent period of 

extended operation. 

Any SLR enhancements 

of the program needed 

for aging management 

and acceptance of the 

TLAA are to be 

incorporated and 

implemented into the 

program at least 

6 months prior to entry 

into the subsequent 

period of extended 

operation. 

*An applicant should incorporate the implementation schedule into its FSAR. The reviewer should verify that the 

applicant has identified and committed in the SLRA to any future aging management activities, including enhancements

and commitments, to be completed before entering the subsequent period of extended operation. The NRC staff 

expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

†If and when published as RG 1.207, Revision 1 Final. 

4.4-1 

4.4 Environmental Qualification (EQ) of Electric Equipment 

Review Responsibilities 

Primary—Branch responsible for electrical engineering 

Secondary—None 

4.4.1 Areas of Review 

The U.S. Nuclear Regulatory Commission (NRC) has established environmental qualification 

(EQ) requirements in the Title 10 of the Code of Federal Regulations (10 CFR) Part 50, 

Appendix A, Criterion 4, and 10 CFR 50.49. Section 50.49 specifically requires each nuclear 

power plant licensee to establish a program to qualify certain electric equipment (not including 

equipment located in mild environments) so that such equipment, up to its end-of-life condition 

(qualified life), will meet its performance specifications during and following design basis accidents 

under the most severe environmental conditions postulated at the equipment’s respective 

location. Such conditions include, among others, conditions resulting from a design basis event 

such as a loss of coolant accident (LOCA), high-energy line break, and post-LOCA environments. 

Electric equipment is qualified to perform its safety function in its respective harsh environment 

after the effects of in-service (operational) aging. Per 10 CFR 50.49, the effects of significant 

aging mechanisms are addressed as part of EQ. Those components with a qualified life equal to 

or greater than the duration of the current plant operating term are covered by time-limited aging 

analyses (TLAAs). 

For equipment located in a harsh environment, the objective of EQ is to demonstrate with 

reasonable assurance that electric equipment important to safety, for which a qualified life has 

been established, can perform its safety function(s) without experiencing common cause failures 

before, during or after applicable design basis events. 

For equipment located in a mild environment (an environment that at no time would be 

significantly more severe than the environment occurring during normal operation, including 

anticipated operational occurrences (10 CFR 50.49), the demonstration that the equipment can 

meet its functional requirements during normal environmental conditions and anticipated 

operational occurrences is in accordance with the plant’s design and licensing bases. Equipment 

important to safety located in a mild environment is not part of an EQ program according to 

10 CFR 50.49(c). Documents that demonstrate that a component is qualified or designed for a 

mild environment include design/purchase specifications, seismic qualification reports, an 

evaluation or certificate of conformance as applicable.

Some nuclear power plants have mechanical 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 a performance of a TLAA, it should be performed in accordance with the 

provisions of Standard Review Plan for Review of Subsequent License Renewal (SRP-SLR) 

Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses.” If a TLAA of qualified 

mechanical equipment is necessary, usually it will involve assessments of the environmental 

effects on consumable components such as seals, gaskets, lubricants, fluids for hydraulic 

systems, or diaphragms. 
4.4-2 

4.4.1.1 Time-Limited Aging Analysis 

All operating plants must meet the requirements of 10 CFR 50.49 for certain important-to-safety 

electrical components. It defines the scope of components to be included, requires the 

preparation and maintenance of a list of in-scope components, and requires the preparation and 

maintenance of a qualification file that includes component performance specifications, electrical 

characteristics, and environmental conditions. The provisions of 10 CFR 50.49(e) require, in part, 

consideration of all significant types of aging degradation that can affect component functional 

capability. Additionally, 10 CFR 50.49(e)(5) requires component replacement or refurbishment 

prior to the end of designated life, unless additional life is established through reanalysis or 

ongoing qualification. Four methods of demonstrating qualification for aging and accident 

conditions are established by 10 CFR 50.49(f). Different qualification criteria are permitted by 

10 CFR 50.49(k) and based on plant and component vintage. Supplemental EQ regulatory 

guidance for compliance with these different qualification criteria is provided in NRC Regulatory 

Guide 1.89, Rev. 1, “Environmental Qualification of Certain Electric Equipment Important to Safety 

for Nuclear Power Plants” (Ref. 1), and the Division of Operating Reactors (DOR) Guidelines 

(Ref. 2), and NUREG–0588 (Ref. 3). The principal nuclear industry qualification standards for 

electric equipment are Institute of Electrical and Electronics Engineers (IEEE) STD 323-1971 

(Ref. 4) and IEEE STD 323-1974 (Ref. 5). These standards contain explicit EQ considerations 

based on TLAAs. Compliance with 10 CFR 50.49 provides reasonable assurance that the 

component can perform its intended functions during and following accident conditions after 

experiencing the effects of in-service aging for applicable equipment. 

4.4.1.1.1 Division of Operating Reactors Guidelines 

The qualification of electric equipment that is subject to significant known degradation due to aging 

where a qualified life was previously required to be established in accordance with Section 5.2.4 of 

the DOR Guidelines is reviewed for the subsequent period of extended operation according to 

those requirements. If a qualified life was not previously established, the qualification is reviewed 

in accordance with Section 7 of the DOR Guidelines. In addition, 10 CFR 50.49(l) should be 

addressed for replacement equipment. 

4.4.1.1.2 NUREG–0588, Category II (IEEE STD 323-1971) 

The qualification of certain electric equipment important to safety for which qualification was 

required in accordance with NUREG–0588, Category II, is reviewed for conformance to those 

requirements for the subsequent period of extended operation to assess the validity of the 

extended qualification. These requirements include IEEE STD 382-1972 (Ref. 6) for valve 

operators and IEEE STD 334-1971 (Ref. 7). In addition, 10 CFR 50.49(l) has to be addressed for 

replacement equipment. 

4.4.1.1.3 NUREG–0588, Category I (IEEE STD 323-1974) 

The qualification of certain electric equipment important to safety for which qualification was 

required in accordance with NUREG–0588, Category I, is reviewed for conformance to those 

requirements for the subsequent period of extended operation to assess the validity of the 

extended qualification. 
4.4-3 

4.4.1.2 Generic Safety Issue 

Regulatory Issue Summary (RIS) 2003-09 was issued on May 2, 2003, (Ref. 8) to inform 

addressees of the results of the technical assessment of generic safety issue (GSI)-168, 

“Environmental Qualification of Electrical Equipment” (Ref. 9). This RIS requires no action on the 

part of the addressees. 

4.4.1.3 Final Safety Analysis Report Supplement 

The detailed information on the evaluation of TLAAs is contained in the subsequent license 

renewal application (SLRA). A summary description of the evaluation of TLAAs for the period of 

extended operation is contained in the applicant’s Final Safety Analysis Report (FSAR) 

supplement. The FSAR Supplement is an area of review. 

4.4.2 Acceptance Criteria 

The acceptance criteria for the areas of review described in Subsection 4.4.1 of this review plan 

section delineate acceptable methods for meeting the requirements of the NRC’s regulations in 

10 CFR 54.21(c)(1). 

4.4.2.1 Time-Limited Aging Analysis 

For long-term operation, TLAAs are reviewed to determine continued acceptability of the analyzed 

component for the subsequent period of extended operation. The time-dependent parameter is 

reevaluated, analyzed or assumed to determine a value that applies to the subsequent period of 

extended operation. This new value of the time-dependent parameter is then used to reevaluate 

the analysis parameter, applicable to the subsequent period of extended operation. 

Pursuant to 10 CFR 54.21(c)(1)(i)–(iii), the TLAA is acceptable if it meets one of the 

following cases: 

(i) The analysis remains valid for the subsequent period of extended operation. The 

time dependent parameter(s) for the subsequent period of extended operation does not 

exceed the time-dependent parameter value used in the existing EQ analysis. 

(ii) The analysis has been projected to the end of the subsequent period of extended 

operation and remains acceptable for the subsequent period of extended operation. The 

time-dependent parameter(s) is projected for the subsequent period of extended 

operation. The value of the time-dependent analysis parameter(s) remains bounded to 

the value used in the existing EQ analysis. 

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

subsequent period of extended operation. 

Specific acceptance criteria for EQ of certain electric equipment important to safety analyzed to 

Section 5.2.4 of the DOR Guidelines; NUREG–0588, Category II (Section 4); or NUREG–0588, 

Category I, depend on the applicant’s choice, that is, 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are: 
4.4-4 

4.4.2.1.1 10 CFR 54.21(c)(1)(i) 

The existing qualification is based on previous testing, analysis, or OE, or combinations thereof 

that demonstrate that the equipment is qualified for the period of extended operation. For option 

(i), the aging evaluation existing at the time of the SLRA for the component remains valid for the 

subsequent period of extended operation, and no further evaluation is necessary. 

4.4.2.1.2 10 CFR 54.21(c)(1)(ii) 

Qualification of the equipment is extended for the subsequent period of extended operation by 

testing, analysis, or OE, or combinations thereof, in accordance with the CLB. For option (ii), a 

reanalysis of the aging evaluation is performed in order to project the qualification of the 

component through the subsequent period of extended operation. Important reanalysis attributes 

of an aging evaluation include analytical methods, data collection and reduction methods, 

underlying assumptions, acceptance criteria, and corrective actions if acceptance criteria are not 

met. These reanalysis attributes are discussed in Table 4.4-1. 

4.4.2.1.3 10 CFR 54.21(c)(1)(iii) 

In Chapter X of the Generic Aging Lessons Learned for Subsequent License Renewal 

(GALL-SLR) Report (Ref. 10), the NRC staff has evaluated the EQ program (10 CFR 50.49) and 

determined that it is an acceptable aging management program (AMP) to address EQ according 

to 10 CFR 54.21(c)(1)(iii). The GALL-SLR Report may be referenced in an SLRA and should be 

treated in the same manner as an approved topical report. However, the GALL-SLR Report 

contains one acceptable way and is not the only way to manage aging for subsequent 

license renewal. 

In referencing the GALL-SLR Report, the applicant should indicate that the material referenced is 

applicable to the specific plant involved and should provide the information necessary to adopt the 

finding of program acceptability as described and evaluated in the report. The applicant should 

also verify that the approvals set forth in the GALL-SLR Report for the generic program apply to 

the applicant’s program. 

4.4.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

should contain sufficient information associated with the TLAAs for the reviewer to determine that 

the applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

4.4.3 Review Procedures 

For each area of review described in Subsection 4.4.1, the following review procedures should 

be followed: 

4.4.3.1 Time-Limited Aging Analysis 

For electric equipment qualified to the requirements of 10 CFR 50.49, the review procedures 

depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), which are: 
4.4-5 

4.4.3.1.1 10 CFR 54.21(c)(1)(i) 

The documented results, test data, analyses, etc., of the previous qualification, which consisted of 

an appropriate combination of testing, analysis, and operating experience (OE), are reviewed 

to confirm that the original qualified life remains valid for the subsequent period of extended 

operation. 

4.4.3.1.2 10 CFR 54.21(c)(1)(ii) 

The results of projecting the qualification to the end of the subsequent period of extended 

operation are reviewed. The qualification methods include testing, inspection, OE, reanalysis, 

ongoing qualification or combinations thereof. 

The reanalysis of an aging evaluation is normally performed to extend the qualification by 

reevaluating original attributes, assumptions and conservatisms for environmental conditions and 

other factors to identify excess conservatisms incorporated in the prior evaluation. Reanalysis of 

an aging evaluation to extend the qualification of electrical equipment is performed pursuant to 

10 CFR 50.49(e) as part of an EQ program. While an electrical equipment life limiting condition 

may be due to thermal, radiation, or operational/testing and cyclic aging, the majority of electrical 

equipment aging limits are based on thermal conditions. Conservatism may exist in aging 

evaluation parameters, such as the assumed service conditions including temperature and 

radiation, loading, power, signal conditions, cycles, and application (e.g., de-energized versus 

energized), or the use of an unrealistically low activation energy. 

The reanalysis of an aging evaluation is performed according to the station’s quality assurance 

program requirements, which requires the verification of assumptions and conclusions including 

the maintenance of required margins and uncertainties. 

For reanalysis, the reviewer verifies that an applicant has completed its reanalysis, addressing 

attributes of analytical methods, data collection and reduction methods, underlying assumptions, 

acceptance criteria, and corrective actions if acceptance criteria are not met (see Table 4.4-1). 

The reviewer also verifies that the reanalysis has been completed in a timely manner prior to the 

end of qualified life. 

4.4.3.1.3 10 CFR 54.21(c)(1)(iii) 

The applicant may reference the GALL-SLR Report in its SLRA, as appropriate. The review 

should verify that the applicant has stated that the report is applicable to its plant with respect to 

its EQ program. The reviewer verifies that the applicant has identified the appropriate AMP as 

described and evaluated in the GALL-SLR Report. The reviewer also verifies that the applicant 

has stated that its EQ program contains, and is consistent with, the same program elements that 

the NRC staff evaluated and relied upon in approving the corresponding generic AMP in the 

GALL-SLR Report. No further NRC staff evaluation is necessary. 

If the applicant does not reference the GALL-SLR Report in its renewal application, additional 

NRC staff evaluation is necessary to determine whether the applicant’s TLAA analysis and EQ 

AMP is acceptable for this area of review. 
4.4-6 

4.4.3.2 Final Safety Analysis Report Supplement 

The reviewer verifies that the applicant has provided information to be included in the FSAR 

Supplement that includes a summary description of the TLAA evaluation of the applicant’s EQ 

AMP including time dependent electric equipment. Table 4.4-2 contains examples of acceptable 

FSAR Supplement information for this TLAA. The reviewer verifies that the applicant has 

provided a FSAR Supplement with information consistent with that in Table 4.4-2 including 

plant-specific commitments, license conditions, enhancements or exceptions. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

4.4.4 Evaluation Findings 

The reviewer determines whether the applicant has provided information sufficient to satisfy the 

provisions of this section and whether the applicant’s evaluation supports conclusions of the 

applicant’s TLAA evaluation. Depending on the applicant’s selection, a review of the applicant’s 

10 CFR 54.21(c)(1)(i), (ii), or (iii) evaluation is to be included in the NRC staff’s Safety 

Evaluation Report: 

On the basis of its review, the NRC staff concludes that the applicant has 

provided an acceptable demonstration, pursuant to 10 CFR 54.2 (c)(1), that, for 

the environmental qualification of Electric Equipment TLAA, [choose which is 

appropriate] 

(i) the analyses remain valid for the subsequent period of extended 

operation, 

(ii) the analyses have been projected to the end of the subsequent period of 

extended operation, or 

(iii) the effects of aging on the intended function(s) will be adequately 

managed for the subsequent period of extended operation. The staff also 

concludes that the FSAR Supplement contains an appropriate summary 

description of electrical equipment TLAA evaluation for the subsequent 

period of extended operation. 
4.4-7 

4.4.5 References 

1. NRC. Regulatory Guide 1.89, “Environmental Qualification of Certain Electric Equipment 

Important to Safety for Nuclear Power Plants.” Revision 1. Agencywide Documents 

Access and Management System (ADAMS) Accession No. ML14070A119. 

Washington, DC: U.S. Nuclear Regulatory Commission. May 20, 1984. 

2. NRC. “Guidelines for Evaluating Environmental Qualification of Class 1E Electrical 

Equipment in Operating Reactors.” DOR Guidelines. ADAMS Accession No. 

ML032541214. Washington, DC: U.S. Nuclear Regulatory Commission. 

November 13, 1979. 

3. NRC. NUREG–0588, “Interim Staff Position on Environmental Qualification of 

Safety-Related Equipment.” ADAMS Accession No. ML031480402. Washington, DC: 

U.S. Nuclear Regulatory Commission. July 31, 1981. 

4. IEEE. IEEE Standard 323-1971, “IEEE Trial Use Standard; General Guide for Qualifying 

Class 1E Equipment for Nuclear Power Generating Stations.” ADAMS Accession No. 

ML032200240. New York, New York: Institute of Electrical and Electronics Engineers. 

September 16, 1971. 

5. IEEE. IEEE Standard 323-1974, “IEEE Standard for Qualifying Class 1E Equipment for 

Nuclear Power Generating Stations.” ADAMS Accession No. ML03220206. New York, 

New York: Institute of Electrical and Electronics Engineers. December 31, 1974. 

6. IEEE. IEEE Standard 382-1972, “Standard for Qualification of Actuators for Power 

Operated Valve Assemblies with Safety Related Functions for Nuclear Power Plants.” 

ADAMS Accession No. ML032200228. New York, New York: Institute of Electrical and 

Electronics Engineers. April 10, 1973. 

7. IEEE. IEEE Standard 334-1971, “IEEE Standard for Type Tests of Continuous Duty Class 

1E Motors for Nuclear Power Generating Stations.” New York, New York: Institute of 

Electrical and Electronics Engineers. 

8. NRC. Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

Instrumentation and Control Cables.” ADAMS Accession No. ML031220078. 

Washington, DC: U.S. Nuclear Regulatory Commission. May 2, 2003. 

9. NRC. “Environmental Qualification of Low-Voltage Instrumentation and Control Cables.” 

Generic Safety Issue-168. ADAMS Accession No. ML022910316. Washington, DC: 

U.S. Nuclear Regulatory Commission. August 16, 2002. 

10. NRC. “Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) 

Report.” Washington, DC: U.S. Nuclear Regulatory Commission. 

11. 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

2016.

12. 10 CFR 50.49, “Environmental Qualification of Electrical Equipment Important to Safety for 

Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016.
4.4-8 

13. NRC. Regulatory Guide 1.211, “Qualification of Safety-Related Cables and Field Splices 

for Nuclear Power Plants.” ADAMS Accession No. ML082530205. Washington, DC: 

U.S. Nuclear Regulatory Commission. April 1, 2009. 

14. NRC. Regulatory Guide 1.100, “Seismic Qualification of Electrical and Active Mechanical 

Equipment and Functional Qualification of Active Mechanical Equipment for Nuclear 

Power Plants.” ADAMS Accession No. ML0913204680. Washington, DC: U.S. Nuclear 

Regulatory Commission. September 30, 2009. 

15. NRC. Regulatory Guide 1.218, “Condition-Monitoring Techniques for Electric Cables Used 

in Nuclear Power Plants.” ADAMS Accession No. ML103510458. Washington, DC: 

U.S. Nuclear Regulatory Commission. April 30, 2012. 

16. IEEE. IEEE Standard 1205-2014, “IEEE Guide for Assessing, Monitoring, and Mitigating 

Aging Effects on Electrical Equipment Used in Nuclear Power Generating Stations and 

Other Nuclear Facilities.” New York, New York: Institute of Electrical and Electronics 

Engineers. 

17. NRC. Regulatory Guide 1.40, “Qualification of Continuous Duty Safety-Related Motors for 

Nuclear Power Plants.” ADAMS Accession No. ML093080087. Washington, DC: 

U.S. Nuclear Regulatory Commission. February 24, 2012. 

18. NRC. Regulatory Guide 1.73, “Qualification Tests of Electric Valve Operators Installed 

Inside the Containment of Nuclear Power Plants.” ADAMS Accession No. ML003740261. 

Washington, DC: U.S. Nuclear Regulatory Commission. January 31, 1974. 

 
4.4-9 

Table 4.4-1 Environmental Qualification Reanalysis and Ongoing Qualification 

Attributes 

Attributes Description 

Analytical methods The analytical models used in the reanalysis of an aging 

evaluation are the same as those previously applied during the 

prior evaluation. The Arrhenius methodology is an acceptable 

thermal model for performing a thermal aging evaluation. The 

analytical method used for a radiation aging evaluation is to 

demonstrate qualification for the total integrated dose 

(i.e., normal radiation dose for the projected installed life plus 

accident radiation dose). For SLR, one acceptable method of 

establishing the 80-year normal radiation dose is to multiply the 

60-year normal radiation dose by 2.0 (i.e., 80 years/40 years). 

The result is added to the accident radiation dose to obtain the 

total integrated dose for the component. For aging effects 

attributed to cyclic aging, a similar approach may be used. 

Other models may be justified on a case-by case basis. 

Data collection and 

reduction methods 

The identification of excess conservatism in electrical equipment 

service conditions used in the prior aging evaluation is the chief 

method used for a reanalysis. For example, temperature data, 

associated margins, and uncertainties used in an equipment EQ 

evaluation may be based on anticipated plant design 

temperatures found to be conservative when compared to actual 

plant temperature data. When used, plant environmental data 

may be obtained from monitors used for technical specification 

compliance; other installed monitors, measurements made by 

plant operators during rounds, dedicated monitors for EQ 

equipment or combinations of the above. The environmental 

data gathering and analysis method used to identify 

conservatism in the original EQ analysis adequately quantifies 

the EQ equipment in-service environment (e.g., sensor locations 

and number, frequency of measurement, and calendar 

duration), and is shown to maintain qualification margins, 

conservatisms, and uncertainties per 10 CFR 50.49. 

Environmental data measurements are evaluated to establish 

the environmental parameter (e.g., temperature, radiation, 

cycles) used in an analysis. Plant environmental data may be 

used in the aging evaluation in different ways, such as 

(a) directly applying the plant environmental data in the 

evaluation or (b) using the plant environmental data to 

demonstrate conservatism when using plant design values for 

an evaluation. The methodology for environmental monitoring, 

data collection and the analysis of localized EQ equipment 

environmental data used in the reanalysis is documented in the 

record of the reanalysis qualification report. Any changes to 

material activation energy values included as part of a reanalysis 

are justified by the applicant on a plant-specific basis. 
4.4-10 

Table 4.4-1 Environmental Qualification Reanalysis and Ongoing Qualification 

Attributes 

Attributes Description 

Underlying assumptions EQ equipment aging evaluations contain conservatism to 

account for most environmental changes occurring due to plant 

modifications and events. A reanalysis demonstrates that 

adequate margin is maintained consistent with the original 

analysis in accordance with 10 CFR 50.59 requiring certain 

margins and accounting for the unquantified uncertainties 

established in the EQ aging evaluation of the equipment. A 

reanalysis that utilizes initial qualification conservatisms and/or 

in-service environmental conditions (e.g., actual temperature 

and radiation conditions) are part of an EQ program. 

Adverse localized environments are identified during periodic 

inspections, or by operational or maintenance activities that 

affect the operating environment of an environmentally qualified 

component, the affected component is evaluated and 

appropriate corrective actions are taken, which may include 

changes to the qualification bases and conclusions (e.g., 

changes to qualified life). 

Acceptance criteria and 

corrective actions 

The reanalysis of an aging evaluation is used to extend the 

environmental qualification of a component. If the qualification 

cannot be extended by reanalysis, the component must be 

refurbished, replaced, or requalified prior to exceeding the 

current qualified life. A reanalysis should be performed in a 

timely manner (such that sufficient time is available to refurbish, 

replace, or requalify the component if the reanalysis is 

unfavorable). A modification to qualified life either by reanalysis 

or ongoing qualification must demonstrate that adequate margin 

is maintained consistent with the original analysis including 

unquantified uncertainties established in the original EQ 

equipment aging valuation. 

Ongoing Qualification Ongoing qualification techniques may be implemented when 

assessed margins, conservatisms, or assumptions do not 

support reanalysis of an EQ component of electric equipment 

important to safety. The requirements of 10 CFR 50.49 provide 

methods that may be used to evaluate and maintain equipment 

EQ, including qualified life, for the subsequent period of 

extended operation. 

 
4.4-11 

Table 4.4-2 Examples of FSAR Supplement for Environmental Qualification 

Electric Equipment TLAA Evaluation 

10 CFR 54.2(c)(1)(i) Example 

TLAA Description of Evaluation

Implementation 

Schedule*

4.4 Environmental 

qualification of 

electric 

equipment

The original environmental qualification 

qualified life has been shown to remain valid for 

the subsequent period of extended operation.

Completed

10 CFR 54.21(c)(1)(ii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule*

4.4 Environmental 

qualification of 

electric 

equipment

The environmental qualification has been 

projected to the end of the period of extended 

operation. Reanalysis addresses attributes of 

analytical methods, data collection and 

reduction methods, underlying assumptions, 

acceptance criteria, and corrective actions. 

Summary report on 

the methods and 

assumptions are 

submitted in the 

SLRA.

10 CFR 54.21(c)(1)(iii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule*

4.4 Environmental 

qualification of 

electric 

equipment

The existing environmental qualification 

process, in accordance with 10 CFR 50.49, will 

adequately manage aging of environmental 

qualification equipment for the subsequent 

period of extended operation because 

equipment will be replaced prior to reaching the 

end of its qualified life.

Program and SLR 

enhancements, 

when applicable, 

are implemented 

6 months prior to 

the subsequent 

period of extended 

operation

*An applicant should incorporate the implementation schedule into its FSAR. The reviewer should verify that the 

applicant has identified and committed in the SLRA to any future aging management activities, including 

enhancements and commitments, to be completed before entering the subsequent period of extended operation. 

The NRC staff expects to impose a license condition on any renewed license to ensure that the applicant will 

complete these activities no later than the committed date.

4.5-1 

4.5 Concrete Containment Unbonded Tendon Prestress Analysis 

Review Responsibilities 

Primary—Branch responsible for structural engineering 

Secondary—None 

4.5.1 Areas of Review 

The prestressing tendons in prestressed concrete containments undergo losses in prestressing 

forces with time due to creep and shrinkage of concrete and relaxation of the prestressing steel. 

During the design phase, engineers estimated these losses to the end of the prestressed 

containment operating life, normally 40 years. Operating experiences with the trend of 

prestressing forces indicate the prestressing tendons may lose their prestressing forces at a rate 

higher than predicted due to sustained high temperature, as discussed in Information Notice 

(IN) 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete 

Containments.” In addition, loss of prestress or reduction in tendon force can occur due to 

breakage of tendon wires or improper anchorages. Stress corrosion cracking (SCC) in individual 

tendons can also occur and contribute to the loss of tendon prestress if there is a susceptible 

material and environment combination. Moreover, consideration should be given to an increased 

tendon relaxation when replacing existing in service tendons with new. Thus, it is necessary to 

ensure that the applicant addresses existing Time-Limited Aging Analyses (TLAAs) for the 

subsequent period of extended operation. Plant-specific TLAAs regarding loss of prestress 

(e.g., predicted tendon prestress force lower limit–predicted lower limit, bonded tendons) are 

addressed and reviewed in Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses.” 

The adequacy of the prestressing forces in prestressed concrete containments is reviewed for the 

subsequent period of extended operation. 

4.5.2 Acceptance Criteria 

The acceptance criteria for the area of review described in Subsection 4.5.1 delineate acceptable 

methods for meeting the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1). 

4.5.2.1 Time-Limited Aging Analysis 

Pursuant to 10 CFR 54.21(c)(1)(i) through (iii), an applicant must demonstrate one of the following: 

(i) The analyses remain valid for the subsequent period of extended operation; 

(ii) The analyses have been projected to the end of the subsequent period of extended 

operation; or 

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

subsequent period of extended operation. 
4.5-2 

4.5.2.1.1 10 CFR 54.21(c)(1)(i) 

The existing prestressing force evaluation remains valid because: (a) losses of the prestressing 

force are less than the predicted losses, as evidenced from the trend lines constructed from the 

recent inspection, (b) the period of evaluation covers the subsequent period of extended 

operation, and (c) the trend lines of the measured prestressing forces remain above the minimum 

required prestress force specified at anchorages for each group of tendons for the subsequent 

period of extended operation.

4.5.2.1.2 10 CFR 54.21(c)(1)(ii) 

The prediction line of prestressing forces for each group of tendons initially developed for 40 years 

of operation should be extended to 80 years. The applicant demonstrates through analysis the 

unbonded tendon prestressed concrete containment design adequacy remains valid and that the 

trend lines of the measured prestressing forces will stay above the design Minimum Required 

Value in the current licensing basis (CLB) for each group of tendons during the subsequent period 

of extended operation.

4.5.2.1.3 10 CFR 54.21(c)(1)(iii) 

In Chapter X of the Generic Aging Lessons Learned for Subsequent License Renewal 

(GALL-SLR) Report, the NRC staff evaluated a program that assesses the concrete containment 

tendon prestressing forces (aging management program (AMP) X.S1, “Concrete Containment 

Unbonded Tendon Prestress”), and has determined that it is an acceptable AMP to address 

concrete containment tendon prestress according to 10 CFR 54.21(c)(1)(iii), except for operating 

experience (OE). Further evaluation is recommended of the applicant’s OE related to the 

containment prestress force. However, the GALL-SLR Report contains one acceptable way and 

not the only way to manage aging. The GALL-SLR report may be referenced in a subsequent 

license renewal application (SLRA), and is treated in the same manner as an approved 

topical report.

In referencing the GALL-SLR report, an applicant indicates that the material referenced is 

applicable to the specific plant involved and should provide the information necessary to adopt the 

finding of program acceptability as described and evaluated in the report. An applicant also 

verifies that the approvals set forth in the GALL-SLR report for the generic program apply to the 

applicant’s program. 

4.5.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

contains information associated with the TLAAs regarding the basis for determining that the 

applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

4.5.3 Review Procedures 

For each area of review described in Subsection 4.5.1, the following review procedures should 

be followed: 
4.5-3 

4.5.3.1 Time-Limited Aging Analysis 

For a concrete containment prestressing tendon system, the review procedures, depending on the 

applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are: 

4.5.3.1.1 10 CFR 54.21(c)(1)(i) 

The results of a recent inspection to measure the amount of prestress loss are reviewed to ensure 

that the reduction of prestressing force is less than the predicted loss in the existing analysis. The 

reviewer verifies that the trend line of the measured prestressing force, when plotted on the 

predicted prestressing force curve, shows that the existing analysis remains valid for the 

subsequent period of extended operation. 

4.5.3.1.2 10 CFR 54.21(c)(1)(ii) 

The reviewer reviews the trend lines of the measured prestressing forces to ensure that individual 

tendon lift-off forces (rather than average lift-off forces of the sampled tendon group) are 

considered in the regression analysis for the subsequent period of extended operation, as 

discussed in IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete 

Containments.” The reviewer then verifies that the trend lines will stay above the minimum 

required prestressing forces for each group of tendons during the subsequent period of 

extended operation so that the design adequacy is maintained in the subsequent period of 

extended operation. 

4.5.3.1.3 10 CFR 54.21(c)(1)(iii) 

An applicant may reference the GALL-SLR Report in its SLRA, as appropriate. The reviewer 

verifies that the applicant has stated that the report is applicable to its plant with respect to its 

program that assesses the concrete containment tendon prestressing forces. The reviewer 

verifies that the applicant has identified the appropriate program (i.e., GALL-SLR Report 

AMP X.S1) as described and evaluated in the GALL-SLR Report. The reviewer also ensures that 

the applicant has stated that its program contains the same program elements that the NRC staff 

evaluated and relied upon in approving the corresponding generic program in the GALL-SLR 

Report. 

Further evaluation is recommended of the applicant’s OE related to the containment prestress 

force. The applicant’s program should incorporate the relevant OE that occurred at the applicant’s 

plant as well as at other plants. The applicant considers applicable portions of the experience 

with prestressing systems described in IN 99-10. Tendon OE could vary among plants with 

prestressed concrete containments. The difference could be due to the prestressing system 

design (for example, button-heads, wedge or swaged anchorages), environment, or type of 

reactor [pressurized water reactor (PWR) or boiling water reactor (BWR)]. The reviewer reviews 

the applicant’s program to verify that the applicant has adequately considered plant-specific OE. 

If the applicant does not reference the GALL-SLR Report in its SLRA, additional NRC staff 

evaluation is necessary to determine whether the applicant’s program is acceptable for this area 

of review. The reviewer uses the guidance provided in Branch Technical Position RLSB-1 of this 

Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear 

Power Plants to ensure that loss of prestress in the concrete containment prestressing tendons is 

adequately managed so that trend lines will remain above the minimum required prestressing 

forces for each group of tendons for the subsequent period of extended operation. 
4.5-4 

4.5.3.2 Final Safety Analysis Report Supplement 

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. 

Table 4.5-1 contains examples of acceptable FSAR Supplement information for this TLAA. The 

reviewer verifies that the applicant has provided an FSAR Supplement with information equivalent 

to that in Table 4.5-1. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

4.5.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of Section 4.5 and whether the NRC staff’s evaluation supports conclusions of the 

following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

included in the Safety Evaluation Report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that, for the concrete containment tendon prestress TLAA, 

[choose which is appropriate] 

(i) the analyses remain valid for the subsequent period of extended 

operation, 

(ii) the analyses have been projected to the end of the subsequent period of 

extended operation, or 

(iii) the effects of aging on the intended function(s) will be adequately 

managed for the subsequent period of extended operation. The NRC staff 

also concludes that the FSAR Supplement contains an appropriate 

description of the concrete containment tendon prestress TLAA evaluation 

for the subsequent period of extended operation. 

4.5.5 References 

1. NRC. Regulatory Guide 1.35.1, “Determining Prestressing Forces for Inspection of 

Prestressed Concrete Containments.” Agencywide Documents Access and Management 
4.5-5 

System (ADAMS) Accession No. ML003740040. Washington, DC: U.S. Nuclear 

Regulatory Commission. July 1990. 

2. NRC. Information Notice 99-10, “Degradation of Prestressing Tendon Systems in 

Prestressed Concrete Containments.” ADAMS Accession No. ML031500244. 

Washington, DC: U.S. Nuclear Regulatory Commission. April 1999. 
4.5-6 

Table 4.5-1 Examples of FSAR Supplement for Concrete Containment Tendon Prestress 

TLAA Evaluation 

10 CFR 54.21(c)(1)(i) Example

TLAA Description of Evaluation

Implementation 

Schedule* 

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart compressive forces in 

the prestressed concrete containments to resist the internal 

pressure inside the containment that would be generated in the 

event of a loss of coolant accident (LOCA). The prestressing forces 

generated by the tendons diminish over time due to losses in 

prestressing forces in the tendons and in the surrounding concrete. 

The existing prestressing force review and evaluation remains valid 

to the end of the subsequent period of extended operation, and the 

trend lines of the measured prestressing forces will stay above the 

minimum required prestressing forces for each group of tendons to 

the end of this period. 

Completed, 

validation 

provided in the 

SLRA 

10 CFR 54.21(c)(1)(ii) Example

TLAA Description of Evaluation

Implementation 

Schedule*

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart compressive forces in 

the prestressed concrete containments to resist the internal 

pressure inside the containment that would be generated in the 

event of a LOCA. The prestressing forces generated by the 

tendons diminish over time due to losses in prestressing forces in 

the tendons and in the surrounding concrete. The prestressing 

force analysis and evaluation has been completed and determined 

to remain within allowable limits to the end of the subsequent 

period of extended operation, and the trend lines of the measured 

pre-stressing forces will stay above the minimum required 

prestressing forces for each group of tendons to the end of 

this period. 

Completed, 

validation 

provided in the 

SLRA 

10 CFR 54.21(c)(1)(iii) Example

TLAA Description of Evaluation

Implementation 

Schedule* 

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart compressive forces in 

the prestressed concrete containments to resist the internal 

pressure inside the containment that would be generated in the 

event of a LOCA. The prestressing forces generated by the 

tendons diminish over time due to losses of prestressing forces in 

the tendons and in the surrounding concrete. The [identify the 

AMP] developed to monitor the prestressing forces will ensure that, 

during each inspection, the trend lines of the measured 

prestressing forces show that they meet the requirements of the 

ASME Code, Section XI, Subsection IWL, as incorporated by 

reference in 10 CFR 50.55a and as supplemented. If the trend 

lines cross the predicted lower limit lines, corrective actions should 

be taken. The program incorporates plant-specific and industry OE. 

Program and SLR 

enhancements, 

when applicable, 

are implemented 

6 months prior to 

the subsequent 

period of 

extended 

operation. 

*An applicant should incorporate the implementation schedule into its FSAR. The reviewer should verify that the 

applicant has identified and committed in the SLRA to any future aging management activities, including 

enhancements and commitments, to be completed before entering the subsequent period of extended operation. 

The NRC staff expects to impose a license condition on any renewed license to ensure that the applicant will 

complete these activities no later than the committed date. 
4.6-1 

4.6 Containment Liner Plate, Metal Containments, and Penetrations 

Fatigue Analysis 

Review Responsibilities 

Primary—Branch responsible for structural engineering 

Secondary—Branch responsible for mechanical engineering 

4.6.1 Areas of Review 

This section addresses fatigue analyses for containment metal liner plates, metal containments 

(including boiling water reactor (BWR) containment suppression chamber and the vent system), 

and penetrations (including personnel airlocks, equipment hatches, sleeves, dissimilar metal 

welds, and bellows). 

The interior surface of a concrete containment structure is lined with thin metallic plates to provide 

a leak-tight barrier against the uncontrolled release of radioactivity to the environment, as required 

by Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix J. The thickness of 

the liner plates is generally between 1/4-in (6.2 mm) and 3/8-in (9.5 mm). The liner plates are 

attached to the concrete containment wall by stud anchors or structural rolled shapes or both. 

The design process assumes that the liner plates do not carry loads. However, imposed loads or 

conditions (e.g., dead, seismic, thermal, internal pressure, creep and shrinkage) induce cyclic 

stresses in the liner plates. Thus, under design-basis conditions, the liner plates could experience 

cyclic strains. Some plants may have metal containments instead of concrete containments with 

liner plates. The metal containments are designed to carry dead loads and seismic loads in 

addition to the internal pressure and temperature loads. For BWR Mark I metal containments, the 

containment suppression pool torus chamber (wetwell) and the vent system are designed or 

evaluated for hydrodynamic loads associated with actuation of safety relief valves and the 

discharge into the suppression pool chamber. 

Fatigue of the containment liner plates or metal containments may be considered in the design 

based on an assumed number of occurrences and severities of cyclic loads for the current 

operating term. The cyclic loads include reactor building interior temperature variations during 

heatups and cooldowns of the reactor coolant system, loss of coolant accident as applicable, 

annual outdoor temperature variations, thermal loads due to the high energy containment 

penetration piping lines (such as steam and feedwater lines), seismic loads, and pressurization 

due to periodic Type A integrated leak rate tests. The BWR containment suppression pool 

chamber and the vent system are designed or evaluated for the hydrodynamic cyclic loads as 

described in Section 6.2.1.1.C, “Pressure-Suppression Type BWR Containments,” of 

NUREG–0800, “Standard Review Plan.” 

Electrical penetration assemblies are usually sealed canisters penetrating the containment liner 

plate or metal containment barrier such that a pressure boundary between the inboard and 

outboard sides of the penetration exists while maintaining electrical continuity through the device. 

Mechanical penetrations include piping penetrations, access penetrations, drywell head, and fuel 

transfer tubes. High energy piping penetrations and the fuel transfer tubes in some plants are 

equipped with stainless steel (SS) bellow assemblies. These penetrations accommodate loads 

from relative movements between the containment wall (including the liner) and the adjoining 

structures, and from Type B, local leak rate tests. The penetrations have sleeves [up to 3 m 

(10 ft) in length, with a 5- to 8-cm (2- to 3-inch) annulus around the piping] to penetrate the 
4.6-2 

concrete containment wall and allow movement of the piping system. Dissimilar metal welds 

connect the piping penetrations to the bellows or SS plates to provide essentially leak-tight 

penetrations. Historical maintenance records, industry operating experience (OE), and aging 

mechanisms that include degradation due to fatigue and their effects on electrical and mechanical 

penetrations, are discussed in Electric Power Research Institute (EPRI) Topical Report 

TR-1003456, “Aging Management Guideline for Commercial Nuclear Power Plants Electrical and 

Mechanical Penetrations.” 

The containment metal liner plates, metal containments (including BWR containment suppression 

chamber and the vent system), and penetrations (including personnel airlocks, equipment 

hatches, sleeves, dissimilar metal welds, and bellows), may be designed in accordance with 

requirements of Section III of the American Society of Mechanical Engineers Boiler and Pressure 

Vessel Code (ASME Code). If a plant’s code of record requires a fatigue parameter evaluation 

(fatigue analysis or fatigue waiver), then this analysis may be a time-limited aging analysis (TLAA) 

and should be evaluated in accordance with 10 CFR 54.21(c)(1) for the subsequent period of 

extended operation. 

The adequacy of the fatigue parameter evaluations of the containment liner plates, metal 

containments, and penetrations is reviewed in this section for the subsequent period of extended 

operation. The number of cyclic load occurrences assumed in the fatigue parameter evaluations 

should be clearly identified in Section 4.6 of the applicant’s subsequent license renewal 

application (SLRA). The fatigue parameter evaluations of the pressure boundary of process 

piping are reviewed separately following the guidance in Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) Section 4.3, 

“Metal Fatigue.” 

4.6.1.1 Time-Limited Aging Analysis (Fatigue Parameter Evaluations) 

The ASME Code contains explicit requirements for fatigue parameter evaluations 

(fatigue analyses or fatigue waivers), which are TLAAs. Specific requirements are contained in 

the design code of reference for each plant. The severities and the numbers of cycles of actual 

loadings for each cyclic load assumed in the underlying analyses should be verified against the 

numbers and severities of the actual loads projected for the subsequent period of extended 

operation. Monitoring of cyclic loading is accomplished through a TLAA aging management 

program (AMP) consistent with the Generic Aging Lessons Learned for Subsequent License 

Renewal (GALL-SLR) Report, X.M1 “Fatigue Monitoring,” or through a site-specific AMP 

consistent with the guidance provided in the SRP-SLR, Appendix A.1. 

4.6.1.1.1 Fatigue Analyses (ASME Section III, MC or Class 1) 

The ASME Code, Section III, Division 2, “Code for Concrete Containments, Rules for Construction 

of Nuclear Facility Components,” and ASME Code, Section III, Division 1, “Subsection NE, Class 

MC Components, Rules for Construction of Nuclear Facility Components,” require a fatigue 

analysis for liner plates, metal containments, and penetrations that considers all cyclic loads 

based on the anticipated number of cycles. Containment components also may be designed to 

ASME Code Section III Class 1 requirements. A Section III, MC or Class 1 fatigue analysis 

requires the calculation of the cumulative usage factor (CUF) based on the fatigue properties of 

the materials and the expected fatigue service of the component. The ASME code limits the CUF 

to a value less than or equal to one for acceptable fatigue design. The fatigue resistance of the 

liner plates or metal containments, and penetrations during the subsequent period of extended 

operation is an area of review. 
4.6-3 

Other evaluations also contain metal fatigue analysis requirements based on a CUF calculation, 

such as metal bellows designed to ASME NC-3649.4(e)(3) or NE-3366.2(e)(3) standards. 

4.6.1.1.2 Fatigue Waiver Evaluations 

The current licensing basis may include fatigue waiver evaluations that preclude the need for 

performing CUF analyses of structural components. The ASME Code Section III rules for 

performing fatigue waiver evaluations for structural components are analogous to those in the 

Code for performing fatigue waiver evaluations of mechanical components. ASME Code 

NE-3131(d) (1974 editions or later) rules out consideration for earthquake transients unless they 

impact designated liner locations recognized in the specifications. ASME Code NE-3222.4(d) 

“Analysis for Cyclic Operations, Vessels Not Requiring Analysis for Cyclic Operation,” provides for 

a waiver from fatigue analysis when certain cyclic loading criteria are met. 

4.6.1.2 Final Safety Analysis Report Supplement 

The SLRA contains TLAA information for containment liner plates, metal containments, and 

penetrations. A summary description of the evaluation of containment liner plates, metal 

containments, and penetrations TLAAs for the subsequent period of extended operation is also 

contained in the applicant’s proposed final safety analysis report (FSAR) supplement. The FSAR 

Supplement is an area of review. 

4.6.2 Acceptance Criteria 

The acceptance criteria for the areas of review described in Subsection 4.6.1 delineate acceptable 

methods for meeting the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

regulations in 10 CFR 54.21(c)(1). 

4.6.2.1 Time-Limited Aging Analysis 

In some instances, the applicant may identify activities to be performed to verify the assumption 

bases of the fatigue parameter evaluations, the fatigue analyses, or the fatigue waiver 

evaluations. Evaluations of those activities are provided by the applicant. The reviewer assures 

that the applicant’s activities are sufficient to confirm the calculation assumptions for the 

subsequent period of extended operation. 

Pursuant to 10 CFR 54.21(c)(1), an applicant must demonstrate one of the following: 

(i) The analyses remain valid for the subsequent period of extended operation; 

(ii) The analyses have been projected to the end of the subsequent period of extended 

operation; or 

(iii) The effects of aging on the intended function(s) will be adequately managed for 

the subsequent period of extended operation. 

Specific acceptance criteria for fatigue of containment liner plates, metal containments, and 

penetrations are provided in the following subsections. 
4.6-4 

4.6.2.1.1 Fatigue Parameter Evaluations 

For containment liner plates, metal containments, and penetrations that have fatigue parameter 

evaluations, the acceptance criteria are provided in the following subsections depending on the 

applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). This section applies to the evaluations 

identified in Sections 4.6.1.1.1 and 4.6.1.1.2. 

4.6.2.1.1.1 10 CFR 54.21(c)(1)(i) 

The fatigue parameter evaluations remain valid because the numbers of occurrences and 

severities of assumed cyclic loads are not projected to be exceeded during the subsequent period 

of extended operation. 

4.6.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

The fatigue parameter evaluations have been reevaluated based on revised numbers of 

occurrences and severities of assumed cyclic loads for the subsequent period of extended 

operation and have been shown to remain within the allowed limits. 

4.6.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

The applicant proposes an AMP as the basis for demonstrating that the effects of aging on the 

intended function(s) of the structure(s) or component(s) in the fatigue parameter evaluations will 

be adequately managed during the subsequent period of extended operation. GALL-SLR Report 

AMP X.M1 provides one method that may be used to demonstrate compliance with the 

requirement in 10 CFR 54.21(c)(1)(iii). 

An applicant may also propose another AMP to demonstrate compliance with the requirement in 

10 CFR 54.21(c)(1)(iii). If the basis for aging management is a plant-specific AMP, the AMP 

should be defined in terms of the 10 program elements defined in the SRP-SLR, Appendix A.1. 

If an inspection program is proposed as the basis for aging management, the AMP implements 

inspections of the component(s) or structure(s) in the evaluation. The AMP justifies the inspection 

methods and frequencies that are applicable to the component(s) or structure(s), such that the 

TLAA will meet the requirement of 10 CFR 54.21(c)(1)(iii). 

Consistent with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii), an AMP is proposed to 

accept the TLAA in accordance with 10 CFR 54.21(c)(1)(iii) and to manage the effects of 

cumulative fatigue damage or fatigue-induced cracking on the intended functions of the 

components during the subsequent period of extended operation. GALL-SLR Report AMP XI.M1 

provides one AMP that may be used as the basis for accepting the fatigue parameter evaluation 

in accordance with 10 CFR 54.21(c)(1)(iii). However, other GALL-SLR Report AMPs or 

plant-specific AMPs or activities may be used to accept the TLAA in accordance 

10 CFR 54.21(c)(1)(iii) if appropriately justified in the SLRA. 

4.6.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 
4.6-5 

contains information associated with the TLAAs regarding the basis for determining that the 

applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

4.6.3 Review Procedures 

For each area of review described in Subsection 4.6.1, the review procedures in the following 

subsections should be used. 

4.6.3.1 Time-Limited Aging Analysis 

4.6.3.1.1 Fatigue Parameter Evaluations 

For containment liner plates, metal containments, and penetrations with fatigue parameter 

evaluations, the review procedures are provided in the following subsections depending on the 

applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

4.6.3.1.1.1 10 CFR 54.21(c)(1)(i) 

The projected number of occurrences and severities of cyclic loadings at the end of the 

subsequent period of extended operation is compared to the number of occurrences and 

severities of cyclic loadings used in the existing fatigue parameter evaluations. The comparison 

confirms that the number of occurrences and severities of cyclic loadings in the existing 

fatigue parameter evaluations will not be exceeded during the subsequent period of 

extended operation. 

4.6.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

The revised number of occurrences and severities of cyclic loadings projected to the end of the 

subsequent period of extended operation is reevaluated. The revised fatigue parameter 

evaluations based on the projected number of occurrences and severities of cyclic loads are 

reviewed to ensure that the calculated fatigue parameters remain less than the allowed values at 

the end of the subsequent period of extended operation. 

If applicable, the code of record is used for the revised fatigue parameter evaluations, or the 

applicant may update to a later code edition pursuant to 10 CFR 50.55a. In the latter case, the 

reviewer verifies that the requirements in 10 CFR 50.55a are met. 

4.6.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant proposes an AMP or aging management 

activities as the basis for demonstrating that the effects of aging on the intended function(s) of the 

structure(s) or component(s) in the fatigue parameter evaluation will be adequately managed 

during the subsequent period of extended operation. If an AMP corresponding to GALL-SLR 

Report AMP X.M1 is used as the basis for managing cumulative fatigue damage or cracking due 

to fatigue or cyclical loading in the structure(s) or component(s), the reviewer reviews the 

applicant’s AMP against the program elements defined in GALL-SLR Report AMP X.M1. 

An applicant also has the option of proposing another GALL-based AMP, plant-specific AMP, or 

plant-specific activities, or combination thereof, to demonstrate compliance with the requirement in 

10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

management, the reviewer reviews the applicant’s AMP against the program element criteria 
4.6-6 

defined in the applicable AMP section in Appendix A of the GALL-SLR Report. If the basis for 

aging management is a plant-specific AMP or plant-specific aging management activities, the 

reviewer reviews the program element criteria for the AMP or activities against the criteria defined 

in the SRP-SLR, Appendix A.1. 

If a sampling based inspection program (a type of condition monitoring program) is proposed as 

the basis for aging management, the reviewer ensures that the AMP actually performs inspections 

of the component(s) or structure(s) in the evaluation and that the applicant has appropriately 

justified that the inspection bases are capable of managing cumulative fatigue damage or cracking 

by fatigue or cyclical loading in the component(s) or structure(s), such that the TLAA may be 

accepted in accordance with 10 CFR 54.21(c)(1)(iii). 

4.6.3.2 Final Safety Analysis Report Supplement 

The reviewer verifies that the applicant has provided information, to be included in the FSAR 

Supplement, that includes a summary description of the fatigue parameter TLAA evaluations for 

the containment liner plates, metal containments, and penetrations. SRP-SLR Table 4.6-1 

contains examples of acceptable FSAR Supplement information for this TLAA. The reviewer 

verifies that the applicant has provided an FSAR Supplement with information equivalent to that in 

Table 4.6-1. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 

4.6.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this section and to support the following conclusions, depending on the applicant’s 

choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be included in the Safety Evaluation Report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that the [the reviewer inserts the type of fatigue parameter 

evaluation] TLAA evaluations, [choose which is appropriate] 

(i) remains valid for the subsequent period of extended operation, 

(ii) has been projected to the end of the subsequent period of extended 

operation, or 
4.6-7 

(iii) the effects of aging on the intended function(s) will be adequately managed 

during the subsequent period of extended operation. The NRC staff also 

concludes that the FSAR Supplement contains an appropriate summary 

description of the [the reviewer inserts the type of fatigue parameter 

evaluation] TLAA evaluations for the subsequent period of extended 

operation. 

4.6.5 References 

1. NRC. NUREG–0661, “Mark I Containment Long-Term Program Resolution of Generic 

Technical Activity A-7.” Agencywide Documents Access and Management System 

(ADAMS) Accession No. ML072710452. Washington, DC: U.S. Nuclear Regulatory 

Commission. July 1980. 

2. NRC. NUREG–0800, “U.S. Nuclear Regulatory Commission, Standard Review Plan.” 

Section 6.2.1.1.C. ADAMS Accession No. ML070630046. Washington, DC: U.S. Nuclear 

Regulatory Commission. March 2007. 

3. ASME. ASME Code, Section III, Division 2, “Code for Concrete Containments, Rules for 

Construction of Nuclear Facility Components.” New York, New York: The American 

Society of Mechanical Engineers, (as endorsed in Regulatory Guide 1.136, “Design Limits, 

Loading Combinations, Materials, Construction, and Testing of Concrete Containments.”) 

4. ASME. ASME Code, Section III, Division 1, “Rules for Construction of Nuclear Facility 

Components.” New York, New York: The American Society of Mechanical Engineers. 

1974 or later as applicable. 

5. EPRI. EPRI TR–1003456, “Aging Management Guideline for Commercial Nuclear Power 

Plants Electrical and Mechanical Penetrations.” Palo Alto, California: Electric Power 

Research Institute. April 2002. 
4.6-8 

Table 4.6-1 Examples of FSAR Supplement for Containment Liner Plates, Metal 

Containments, and Penetrations Fatigue TLAA Evaluation 

10 CFR 54.21(c)(1)(i) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

Current fatigue parameter evaluations remain valid 

during the subsequent period of extended operation. 

Completed, 

validation provided 

in the SLRA 

10 CFR 54.21(c)(1)(ii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

Fatigue parameter evaluations have been reevaluated 

based on revised numbers of occurrences and severities 

of cyclic loads projected for the subsequent period of 

extended operation. The revised fatigue parameter 

values remain within allowable limits for the subsequent 

period of extended operation. 

Completed, 

validation provided 

in the SLRA 

10 CFR 54.21(c)(1)(iii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

The applicant identifies an AMP to manage the effects of 

fatigue on such components during the subsequent 

period of extended operation. The program monitors 

and tracks the number of cycles and occurrences and 

severities of relevant transients. The program is 

effective when fatigue evaluations and/or fatigue usage 

remain within the allowable limits or requires corrective 

actions (e.g., reanalyses and/or component 

replacement) when the limits are exceeded. If the 

component is replaced, the fatigue parameter value for 

the replacement should be shown to be less than the 

allowable limit during the subsequent period of 

extended operation. 

Program and SLR 

enhancements, 

when applicable, 

are implemented 

6 months prior to 

the subsequent 

period of extended 

operation. 

*An applicant should incorporate the implementation schedule into its FSAR. The reviewer should verify that the 

applicant has identified and committed in the SLRA to any future aging management activities, including 

enhancements and commitments, to be completed before entering the subsequent period of extended operation. 

The NRC staff expects to impose a license condition on any renewed license to ensure that the applicant will 

complete these activities no later than the committed date. 

Note: All containment components need not meet the same requirement. It is likely that the liner plate and the 

bellows may be evaluated per 10 CFR 54.21(c)(1)(i), while high energy penetrations may be evaluated per 

10 CFR 54.21(c)(1)(ii). 
4.7-1 

4.7 Other Plant-Specific Time-Limited Aging Analyses 

Review Responsibilities 

Primary—Branch responsible for time-limited aging analysis (TLAA) issues 

Secondary—Other branches responsible for systems, as appropriate 

4.7.1 Areas of Review 

There are certain plant-specific safety analyses that may involve time-limited assumptions defined 

by the current operating term of the plant (for example, aspects of the reactor vessel design) 

and may, therefore, be TLAAs. Pursuant to Title 10 of the Code of Federal Regulations

(10 CFR) 54.21(c), a subsequent license renewal (SLR) applicant is required to evaluate TLAAs. 

The definition of TLAAs is provided in 10 CFR 54.3 and in Section 4.1 of this Standard Review 

Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

(SRP-SLR). 

As indicated in 10 CFR 54.30, the adequacy of the plant’s current licensing basis (CLB) is not an 

area within the scope of the SLR review. Any questions regarding the adequacy of the CLB must 

be addressed under the backfit rule (10 CFR 50.109) and are separate from the license renewal 

process. SLR reviews focus on the subsequent period of extended operation. Pursuant to 

10 CFR 54.30, if the reviews required by 10 CFR 54.21(a) or (c) show that there is not reasonable 

assurance during the current license term that licensed activities will be conducted in accordance 

with the CLB, the licensee is required to take measures under its current license to ensure that the 

intended functions of those systems, structures, and components (SSCs) are maintained in 

accordance with the CLB throughout the term of the current license. The adequacy of the 

measures for the term of the current license is not within the scope of the SLR review. 

Pursuant to 10 CFR 54.21(c), an applicant must provide a listing of TLAAs and plant-specific 

exemptions that are based on TLAAs. The U.S. Nuclear Regulatory Commission (NRC) staff 

reviews the applicant’s identification of TLAAs and exemptions separately, following the guidance 

in Section 4.1 of this SRP-SLR. 

The NRC staff has developed review procedures for the evaluation of certain TLAAs. If an 

applicant identifies these TLAAs as applicable to its plant, the NRC staff reviews them separately, 

following the guidance in Sections 4.2 through 4.6 of this SRP-SLR. 

Table 4.7-1 provides examples of potential plant-specific TLAA topics. The reviewer follows the 

generic guidance in this section of the SRP-SLR for reviewing these and any other plant-specific 

TLAAs that have been identified by the applicant. For particular systems, the reviewers 

from branches responsible for those systems may be requested to assist in the review, 

as appropriate. 

The following subsections identify the areas of review for plant-specific TLAAs. 

4.7.1.1 Time-Limited Aging Analysis 

The applicant’s evaluation of the TLAA for the subsequent period of extended operation 

is reviewed. 
4.7-2 

4.7.1.2 Final Safety Analysis Report Supplement 

The Final Safety Analysis Report (FSAR) supplement summarizing the applicant’s evaluation of 

the TLAA for the subsequent period of extended operation is reviewed. 

4.7.2 Acceptance Criteria 

The acceptance criteria for the areas of review described in Section 4.7.1 delineate acceptable 

methods for meeting the requirements of 10 CFR 54.21(c)(1) and 10 CFR 54.21(d). 

4.7.2.1 Time-Limited Aging Analysis 

Pursuant to 10 CFR 54.21(c)(1), an applicant must demonstrate one of the following for TLAAs: 

(i) The analyses remain valid for the period of extended operation; 

(ii) The analyses have been projected to the end of the period of extended operation; 

or 

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation. 

Acceptance criteria for each TLAA demonstration are discussed in the following subsections. 

4.7.2.1.1 10 CFR 54.21(c)(1)(i) 

The applicant must demonstrate that the analysis remains valid for the subsequent period of 

extended operation. The analysis remains valid because it is shown to be bounding even during 

the subsequent period of extended operation. No changes to the existing analysis are necessary. 

4.7.2.1.2 10 CFR 54.21(c)(1)(ii) 

The applicant must demonstrate that the analysis has been projected to the end of the 

subsequent period of extended operation. The existing analysis is updated or recalculated to 

show acceptable results for the subsequent period of extended operation. 

4.7.2.1.3 10 CFR 54.21(c)(1)(iii) 

The applicant must demonstrate that the effects of aging on the intended function(s) will be 

adequately managed for the subsequent period of extended operation. Appendix A.1 of this 

SRP-SLR provides the acceptance criteria for programs and activities used to manage the effects 

of aging. 

4.7.2.2 Final Safety Analysis Report Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

evaluation of TLAAs for the subsequent period of operation in the FSAR Supplement is sufficiently 

comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

contains information associated with the TLAAs regarding the basis for determining that the 

applicant has made the demonstration required by 10 CFR 54.21(c)(1). 
4.7-3 

4.7.3 Review Procedures 

For certain applicants, plant-specific analyses may meet the definition of a TLAA as given in 

10 CFR 54.3. The concern for SLR is that these analyses may not have properly considered the 

full length of the subsequent period of extended operation, which may change conclusions with 

regard to safety and the capability of SSCs within the scope of 10 CFR Part 54 to perform one or 

more safety functions. The review of these TLAAs provides assurance that the effects of aging 

are properly addressed through the subsequent period of extended operation.

The following subsections provide the review procedures for each area of review described in 

Section 4.7.1. 

4.7.3.1 Time-Limited Aging Analysis 

For each TLAA, the review procedures depend on the applicant’s choice of methods of 

compliance in 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

4.7.3.1.1 10 CFR 54.21(c)(1)(i) 

Justification provided by the applicant is reviewed to verify that the existing analysis remains valid 

for the subsequent period of extended operation. The existing analysis should be shown to be 

bounding even during the subsequent period of extended operation. 

The applicant describes the TLAA with respect to the objectives of the analysis, assumptions used 

in the analysis, conditions, acceptance criteria, relevant aging effects, and intended function(s). 

For those analyses that consider cyclic loading, each load or transient type should be identified 

along with the corresponding number of total cycles assumed in the analysis and the number of 

cycles that are anticipated to occur through the subsequent period of extended operation. The 

applicant shows that (a) conditions and assumptions used in the analysis already address the 

relevant aging effects for the subsequent period of extended operation, and (b) acceptance 

criteria are maintained to provide reasonable assurance that the intended function(s) is 

maintained. Thus, no reanalysis is necessary. 

In some instances, the applicant may identify activities to be performed to verify the assumption 

basis for the calculation (e.g., cycle counting). An evaluation of that activity is provided by the 

applicant. The reviewer assures that the applicant’s verification activities are sufficient to confirm 

the validity of the calculation assumptions for the subsequent period of extended operation. 

If the TLAA must be modified or recalculated to extend the period of evaluation to consider the 

subsequent period of extended operation, then reevaluation should be addressed under 

10 CFR 54.21(c)(1)(ii). 

4.7.3.1.2 10 CFR 54.21(c)(1)(ii) 

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 subsequent period of extended operation. 

The applicable analysis technique can be the one that is in effect in the plant’s CLB at the time 

that the subsequent license renewal application (SLRA) is filed. 

The applicant may recalculate the TLAA using an 80-year period to show that the acceptance 

criteria continue to be satisfied for the subsequent period of extended operation. The applicant 
4.7-4 

also may revise the TLAA by recognizing and reevaluating any overly conservative conditions and 

assumptions. Examples include relaxing overly conservative assumptions in the original analysis, 

using new or refined analytical techniques, and performing the analysis using an 80-year period. 

The applicant should provide a sufficient description of the analysis and document the results of 

the reanalysis to show that it is satisfactory for the subsequent period of extended operation. 

As applicable, the plant’s code of record is used for the reevaluation, or the applicant may update 

to a later code edition pursuant to 10 CFR 50.55a. In the latter case, the reviewer verifies that the 

requirements in 10 CFR 50.55a are met. 

In some cases, the applicant may identify activities to be performed to verify the assumption basis 

for the calculation (e.g., cycle counting). An evaluation of that activity is provided by the applicant. 

The reviewer assures that the applicant’s verification activities are sufficient to confirm the validity 

of the calculation assumptions for the subsequent period of extended operation. 

4.7.3.1.3 10 CFR 54.21(c)(1)(iii) 

Under this option, the applicant proposes to manage the aging effects associated with the TLAA 

by an aging management program (AMP) or aging management activities in the same manner as 

described in the integrated plant assessment (IPA) in 10 CFR 54.21(a)(3). The reviewer reviews 

the applicant’s AMP or aging management activities to verify that the effects of aging on the 

intended function(s) are adequately managed consistent with the CLB for the subsequent period 

of extended operation. 

The applicant identifies the structures and components (SCs) associated with the TLAA. The 

TLAA is described with respect to the objectives of the analysis, conditions, assumptions used, 

acceptance criteria, relevant aging effects, and intended function(s). The reviewer uses the 

guidance in Section A.1 of this SRP-SLR to ensure that the effects of aging on the SC-intended 

function(s) are adequately managed for the subsequent period of extended operation. 

4.7.3.2 Final Safety Analysis Report Supplement 

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 each TLAA. Each such 

summary description is reviewed to verify that it is sufficiently comprehensive. 

The NRC staff expects to impose a license condition on any renewed license to require the 

applicant to update its FSAR to include this FSAR Supplement at the next update required 

pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

complete, the applicant may make changes to the programs described in its FSAR Supplement 

without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final FSAR 

Supplement before the license is renewed, no condition will be necessary. 

An applicant should incorporate the implementation schedule into its FSAR. The reviewer should 

verify that the applicant has identified and committed in the SLRA to any future aging 

management activities, including enhancements and commitments, to be completed before 

entering the subsequent period of extended operation. The NRC staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities 

no later than the committed date. 
4.7-5 

4.7.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this Section 4.7 and whether the NRC staff’s evaluation supports conclusions of the 

following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

included in the Safety Evaluation Report: 

On the basis of its review, as discussed above, the NRC staff concludes that 

the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that, for the (name of specific) TLAA, [choose which 

is appropriate] 

(i) The analyses remain valid for the subsequent period of extended 

operation, 

(ii) The analyses have been projected to the end of the period of extended 

operation, or 

(iii) The effects of aging on the intended function(s) will be adequately 

managed for the subsequent period of extended operation. The NRC staff 

also concludes that the FSAR Supplement contains an appropriate 

summary description of this TLAA evaluation for the period of extended 

operation, as required by 10 CFR 54.21(d). 

4.7.5 References 

None 
4.7-6 

Table 4.7-1 Examples of Potential Plant-Specific TLAA Topics 

BWRs 

Re-flood thermal shock of the reactor pressure vessel 

Re-flood thermal shock of the core shroud and other reactor vessel internals 

Loss of preload for core plate rim hold-down bolts 

Erosion of the main steam line flow restrictors 

Susceptibility to irradiation-assisted stress corrosion cracking 

PWRs 

Reactor pressure vessel underclad cracking 

Leak-before-break 

Reactor coolant pump flywheel fatigue crack growth 

Response to NRC Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification” 

Response to NRC Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor 

Cooling Systems” 

BWRs and PWRs 

Fatigue of cranes (crane cycle limits) 

Fatigue of the spent fuel pool liner 

Corrosion allowance calculations 

Flaw growth due to stress corrosion cracking 

Predicted lower limit 
5.1-1 

5 TECHNICAL SPECIFICATIONS CHANGES 

5.1 Review of Technical Specifications Changes and Additions Necessary to 

Manage the Effects of Aging During the Subsequent Period of 

Extended Operation 

Review Responsibilities 

Primary—Branch responsible for reviewing technical specifications (TS) requirements related to 

aging management programs (AMPs) or time-limited aging analyses (TLAAs) 

Secondary—Other branches responsible for engineering, as appropriate 

5.1.1 Areas of Review 

The requirements in Title 10 of the Code of Federal Regulations (10 CFR) 54.22 (Ref. 1) require 

an applicant to identify any new TS or TS changes (i.e., amendments) that are needed to manage 

the effects of aging during the subsequent period of extended operations. This section of the 

Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear 

Power Plants (SRP-SLR) provides guidance for determining whether plant TS changes need to 

be included in a plant-specific subsequent license renewal application (SLRA). 

5.1.2 Acceptance Criteria 

The TS for a relicensed light-water reactor facility may contain specific TS sections that may have 

relationships to AMPs or TLAAs that are identified in an SLRA. The following provide examples of 

(but are not limited to) TS requirements that may relate to AMPs or TLAAs: 

 For TS that include administrative controls section provisions that establish preventative 

maintenance and periodic visual inspection requirements for plant systems located outside 

of containment (i.e., for applicant’s whose SLRAs include periodic surveillance and 

preventative maintenance AMPs and whose current licensing basis (CLB) include these 

types of TS requirements), the AMPs should establish the relationship of the TS 

requirements to the applicable program element criteria for their AMPs, as applicable. 

 For TS that include administrative controls section provisions that establish fuel oil testing 

requirements for emergency diesel fuel storage tanks (i.e., for applicant’s whose SLRAs 

include diesel fuel oil testing AMPs and with CLBs that include these types of TS 

requirements), the AMPs should establish the relationship of the TS requirements to the 

applicable program element criteria for their AMPs, as applicable. 

 For TS that include pressure-temperature (P-T) limits for their reactor vessels and reactor 

coolant pressure boundary components in the limiting conditions of operations (LCOs) and 

control updates of these P-T limits through their 10 CFR 50.90 license amendment 

request process, the TS requirements may have direct bearing on how the P-T limit 

TLAAs for the SLRA are accepted in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

 For TS that include P-T limits for their reactor vessels and reactor coolant pressure 

boundary components in a pressure-temperature limit report (PTLR) and controls updates 

of the P-T limits and PTLR in accordance with a program and process controlled by the 
5.1-2 

administrative controls section of their TS, the TS requirements may have direct 

bearing on how the P-T limit TLAAs for the SLRA are accepted in accordance with 

10 CFR 54.21(c)(1)(i), (ii), or (iii). 

Acceptance criteria for plant-specific TS are contained in the specific TS provisions or alternatively 

in referenced documents invoked by the TS requirements. For those SLRAs for plants whose 

CLBs include TS requirements that relate to an AMP’s program element bases for managing 

specific aging effects, the TS requirements should be reviewed to confirm that they remain 

adequate for managing the aging effects that are within the scope of the AMPs. Otherwise, the 

TS requirements should be amended accordingly as part of the SLRA in accordance with 10 CFR 

54.22 and the changes in the TS requirement criteria factored into the program element bases for 

the AMP, as appropriate. 

For those TS requirements that relate to TLAAs, the TS requirements and any methodologies or 

processes invoked by the TS requirements should be reviewed to see if they need to be amended 

or new TS requirements need to be proposed in order to demonstrate adequate compliance of the 

TLAAs in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii). Otherwise, TS changes that are 

determined as being necessary to disposition TLAAs in accordance with the requirements of 

10 CFR 54.21(c)(1)(i), (ii), or (iii) should be included in the SLRA as part of TS change requests 

under 10 CFR 54.22. This may include TS changes that may be needed for P-T limit TLAAs 

controlled by PTLR processes, if it is determined that the current P-T limit methodologies 

approved and invoked by the current administrative controls TS requirements cannot generate 

P-T limits for the subsequent period of extended operation that will comply with the P-T limit 

requirements in 10 CFR Part 50, Appendix G (Ref. 2), and Appendix G of the American Society of 

Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) Section XI edition of 

record for the facility. 

5.1.3 Review Procedures 

The reviewer should review the applicant’s operating license, including the TS that are included as 

part of the operating license, and procedures to ensure that the applicant has identified all 

appropriate TS changes or additions that may impact AMPs or TLAAs during the subsequent 

period of extended operation. If it is determined that new TS requirements, or new operating 

license conditions are needed to manage specific aging effects, or that changes to the existing TS 

requirements need to be amended in order to manage such aging effects, the reviewer 

determines that those license amendments are submitted with the SLRA for U.S. Nuclear 

Regulatory Commission (NRC) approval in accordance with the requirement in 10 CFR 54.22. 

Examples of existing TS requirements that may be used to manage the effects of aging include 

but are not limited to: (a) preventative maintenance and periodic visual inspection requirements 

for plant systems located outside of containment, (b) diesel fuel oil monitoring requirements or 

surveillance requirements that are listed in the administrative controls sections of the TS, which 

may form the bases for fuel oil chemistry programs used to manage loss of material due to 

general, pitting, crevice, and microbiologically-induced corrosion in emergency diesel fuel oil 

system components, and (c) requirements in the TS that govern the applicant’s updates to the P-T 

limits of their plants that constitute part of the mandatory bases for managing and analyzing loss 

of fracture toughness due to neutron irradiation embrittlement in ferritic steel components of the 

reactor vessel and reactor coolant pressure boundary. This latter example is a TLAA. 
5.1-3 

5.1.4 Evaluation Findings 

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of this section, and whether the NRC staff’s evaluation supports one of the following 

three conclusions listed below that is to be included in the NRC staff’s safety evaluation report, as 

applicable for the review of the SLRA: 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has provided an acceptable basis for concluding that the SLRA does not 

need to include any new TS requirements or TS amendments to manage the 

effects of aging during the subsequent period of extended operation. 

On the basis of its review, as discussed above, the NRC staff concludes that the 

applicant has provided a list of all new TS provisions or TS changes in the SLRA 

that are needed to manage the effects of aging during the subsequent period of 

extended operation , as required by 10 CFR 54.22. The NRC staff also concludes 

that these TS changes will be capable of managing the effects of aging in 

accordance the requirement in 10 CFR 54.21(a)(3). 

Pursuant to the requirement in 10 CFR 54.22, as discussed above, the NRC staff 

concludes that the applicant has provided those new TS provisions or TS changes 

in the SLRA needed to manage [INSERT APPLICABLE AGING EFFECT], as 

evaluated in [INSERT NAME of TLAA] for the subsequent period of extended 

operation. The NRC staff also concludes that these TS changes adequately 

demonstrate that the [INSERT NAME of TLAA and then INSERT one of the 

Following Statements to finish off this conclusion] . . .will remain valid for the 

subsequent period of extended operation, as required by 10 CFR 54.21(c)(1)(i),” 

has been adequately projected to the end of the subsequent period of extended 

operation, as required by 10 CFR 54.21(c)(1)(ii),” effects of [INSERT APPLICABLE 

AGING EFFECT AND MECHANISM] on the intended functions of the [INSERT 

APPLICABLE STRUCTURES OR COMPONENTS EVALUATED IN THE TLAA] 

during the SLR period, as required by 10 CFR 54.21(c)(1)(iii). 

5.1.5 References 

1. 10 CFR 54.22, “Contents of Application–Technical Specifications.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016.

2. 10 CFR Part 50, Appendix G, “Fracture Toughness Requirements.” Washington, DC: 

U.S. Nuclear Regulatory Commission. 2016.

APPENDIX A 

GENERAL NRC STAFF POSITIONS AND GUIDANCE 

A.1-1 

APPENDIX A—GENERAL NRC STAFF POSITIONS AND GUIDANCE 

A.1 Aging Management Review—Generic 

(Branch Technical Position RLSB-1) 

A.1.1 Background 

Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(3), a license renewal 

application is required to demonstrate that the effects of aging on structures and components 

(SCs) subject to an aging management review (AMR) are adequately managed so their intended 

functions will be maintained consistent with the current licensing basis (CLB) for the subsequent 

period of extended operation. The purpose of this Branch Technical Position (RLSB-1) is to 

address the aging management demonstration that has not been addressed specifically in 

Chapters 3 and 4 of this Standard Review Plan for Review of Subsequent License Renewal 

Applications for Nuclear Power Plants (SRP-SLR). 

The subsequent license renewal (SLR) process is not intended to demonstrate absolute 

assurance that SCs will not fail, but rather that there is reasonable assurance that they will 

perform such that the intended functions are maintained consistent with the CLB during the 

subsequent period of extended operation. 

There are four types of aging management programs (AMPs): (i) prevention, (ii) mitigation, (iii) 

condition monitoring, and (iv) performance monitoring. 

Prevention Programs preclude the effects of aging. For example, coating programs prevent 

external corrosion of a tank. 

Mitigation Programs attempt to slow the effects of aging. For example, water chemistry programs 

mitigate internal corrosion of piping. 

Condition Monitoring Programs inspect for the presence and extent of aging effects or perform 

tests that monitor potential changes in a components or structure’s material condition. Examples 

of programs that involve inspections are the visual examination of concrete structures for cracking 

and the ultrasonic examination of pipe wall for flow-accelerated corrosion (FAC)-induced wall 

thinning. Examples of programs that involve material testing are reactor pressure vessel material 

surveillance capsule testing programs that monitor for embrittlement in ferritic reactor pressure 

vessel components and material testing programs that monitor for degradation in spent fuel pool 

neutron absorption materials. 

Performance Monitoring Programs test the ability of a structure or component to perform its 

intended function(s). For example, the ability of the tubes on heat exchangers to transfer heat 

is tested. 

More than one type of AMP may be implemented to ensure that aging effects are managed. For 

example, in managing internal corrosion of piping, a mitigation program (water chemistry) may be 

used to minimize susceptibility to corrosion. However, it may also be necessary to have a 

condition monitoring program (ultrasonic inspection) to verify that corrosion is indeed insignificant. 

In addition, some AMPs may incorporate more than one of the activities of prevention, mitigation, 

condition monitoring, or performance monitoring. For example, open cycle cooling water 

programs may incorporate combinations of inspection (condition monitoring) and flow testing 

(performance monitoring) activities. 
A.1-2 

A.1.2 Branch Technical Position 

A.1.2.1 Applicable Aging Effects 

1. The determination of applicable aging effects is based on degradation mechanisms that 

have occurred and those that potentially could cause SC degradation. The materials, 

environment, stresses, service conditions, operating experience (OE), and other relevant 

information should be considered in identifying applicable aging effects. The effects of 

aging on the intended function(s) of SCs also should be considered. 

2. Relevant aging information may be contained in, but is not limited to, the following 

documents: (i) plant-specific maintenance and inspection records; (ii) plant-specific site 

deviation or issue reports; (iii) plant-specific U.S. Nuclear Regulatory Commission (NRC) 

and Institute of Nuclear Power Operations (INPO) inspection reports; (iv) plant-specific 

licensee self-assessment reports; (v) plant-specific and other licensee event reports; 

(vi) NRC, INPO, and vendor generic communications; and (vii) generic safety issues/ 

unresolved safety issues; NUREG reports; and Electric Power Research Institute 

(EPRI) reports. 

3. If OE or other information indicates that a certain aging effect may be applicable and an 

applicant determines that it is not applicable to its specific plant, the reviewer may 

question the absence of this aging effect if the applicant has not provided a sufficient 

basis in its subsequent license renewal application. For example, the question could cite 

a previous application review, NRC generic communications, engineering judgment, 

relevant research information, or other industry experience as the basis for the question. 

Simply citing that the aging effect is listed in the Generic Aging Lessons Learned for 

Subsequent License Renewal (GALL-SLR) Report is not a sufficient basis. For 

example, it may be that the aging effect is applicable to a pressurized water reactor 

(PWR) component, but the applicant’s plant is a boiling water reactor (BWR) and does 

not have such a component. In this example, using the GALL-SLR Report merely as a 

checklist is not appropriate. 

4. An aging effect may not have been identified in the GALL-SLR Report, if it arises out of 

industry experience after the issuance of the GALL-SLR Report. The reviewer should 

ensure that the applicant has evaluated the latest industry experience to identify all 

applicable aging effects. 

5. An aging effect should be identified as applicable for SLR even if there is a prevention or 

mitigation program associated with that aging effect. For example, water chemistry, a 

coating, or use of cathodic protection could prevent or mitigate corrosion, but corrosion 

should be identified as applicable for SLR, and the AMR should consider the adequacy 

of the AMP referencing water chemistry, coating, or cathodic protection. 

6. Specific identification of aging mechanisms is not a requirement; however, it is an option 

to identify specific aging mechanisms and the associated aging effects in the integrated 

plant assessment. 

7. The applicable aging effects to be considered for SLR include those that could result 

from normal plant operation, including plant or system operating transients and plant 

shutdown. Specific aging effects from abnormal events need not be postulated for SLR. 

However, if an abnormal event has occurred at a particular plant, its contribution to the 
A.1-3 

aging effects on SCs for SLR should be considered for that plant. For example, if a resin 

intrusion has occurred in the reactor coolant system at a particular plant, the contribution 

of this resin intrusion event to aging should be considered for that plant. 

Design basis events (DBEs) are abnormal events; they include design basis pipe break, 

loss-of-coolant accident, and safe shutdown earthquake. Potential aging effects resulting from 

DBEs are addressed, as appropriate, as part of the plant’s CLB. There are other abnormal events 

which should be considered on a case-by-case basis. For example, abuse due to human activity 

is an abnormal event; aging effects from such abuse need not be postulated for SLR. When a 

safety-significant piece of equipment is accidentally damaged by a licensee, the licensee is 

required to take immediate corrective action under existing procedures (see 10 CFR Part 50 

Appendix B) to ensure functionality of the equipment. The equipment degradation is not due to 

aging; corrective action is not necessary solely for the subsequent period of extended operation. 

However, leakage from bolted connections should not be considered as abnormal events. 

Although bolted connections are not supposed to leak, experience shows that leaks do occur, and 

the leakage could cause corrosion. In addition, condensation frequently occurs during humid 

periods of normal plant operation and can also occur during plant shutdown when normally hot 

components might be below the dew point. The aging effects from leakage of bolted connections 

and condensation occurring during humid periods of normal plant operations should be evaluated 

for SLR. Condensation during plant shutdowns could result in aging effects such as reduced 

thermal insulation resistance due to moisture intrusion and should be evaluated for SLR. It is 

less likely that condensation during plant shutdowns would result in loss of material, unless 

plant-specific OE dictates otherwise (e.g., as a result of extended plant shutdowns). 

An aging effect due to an abnormal event does not preclude that aging effect from occurring 

during normal operation for the subsequent period of extended operation. For example, a certain 

PWR licensee observed clad cracking in its pressurizer, and attributed that to an abnormal dry out 

of the pressurizer. Although dry out of a pressurizer is an abnormal event, the potential for clad 

cracking in the pressurizer during normal operation should be evaluated for SLR. This is because 

the pressurizer is subject to extensive thermal fluctuations and water level changes during plant 

operation, which may result in clad cracking given sufficient operating time. The abnormal dry out 

of the pressurizer at that certain plant may have merely accelerated the rate of the aging effect. 

A.1.2.2 Aging Management Program for Subsequent License Renewal 

1. An acceptable AMP should consist of the 10 elements described in Table A.1-1, as 

appropriate. These program elements are discussed further in Position A.1.2.3 below. 

2. All programs and activities that are credited for managing a certain aging effect for a 

specific structure or component should be described. These programs and activities 

may be evaluated together for the 10 elements described in Table A.1-1, as appropriate. 

3. The risk significance of a structure or component could be considered in evaluating the 

robustness of an AMP. Probabilistic arguments may be used to develop an approach for 

aging management adequacy. However, use of probabilistic arguments alone is not an 

acceptable basis for concluding that, for those SCs subject to an AMR, the effects of 

aging will be adequately managed in the subsequent period of extended operation. 

Thus, risk significance may be considered in developing the details of an AMP for the 

structure or component for SLR, but may not be used to conclude that no AMP is 

necessary for SLR. 
A.1-4 

4. For programs that rely on NRC-endorsed technical or topical reports (TRs), the scope of 

the AMP includes the applicant’s bases for resolving or addressing any NRC limitations 

or applicant/licensee action items that are placed on the activities for implementing a 

given report’s methodology. These limitations or action items are identified in the NRC’s 

safety evaluation on the TR’s methodology and recommended activities. If it is 

determined that the response to a specific applicant action item will result in the need for 

augmentation of specific programmatic criteria beyond those activities recommended in 

the applicable TR, the applicant should define the AMP accordingly to identify the AMP 

program element or elements that are impacted by the basis for responding to the 

applicable action item and the adjustments that will need to be made to the TR guidance 

recommendations, as defined in the impacted program elements for the AMP and 

applicable to the CLB and design basis for the facility. It is also recommended that the 

applicants provide their bases for resolving the specific limitations or action items in 

Appendix C of their SLRAs. 

A.1.2.3 Aging Management Program Elements 

A.1.2.3.1 Scope of Program 

The specific program necessary for SLR should be identified. The scope of the program should 

include the specific SCs, the aging of which the program manages. 

A.1.2.3.2 Preventive Actions 

1. The activities for prevention and mitigation programs should be described. These 

actions should mitigate or prevent aging degradation. 

2. Some condition or performance monitoring programs do not rely on preventive actions 

and thus, this information need not be provided. 

3. In some cases, condition or performance monitoring programs may also rely on 

preventive actions. The specific prevention activities should be specified. 

A.1.2.3.3 Parameters Monitored or Inspected 

1. This program element should identify the aging effects that the program manages and 

should provide a link between the parameter or parameters that will be monitored and 

how the monitoring of these parameters will ensure adequate aging management. 

2. For a condition monitoring program, the parameter monitored or inspected should be 

capable of detecting the presence and extent of aging effects. Some examples are 

measurements of wall thickness and detection and sizing of cracks. 

3. For a performance monitoring program, a link should be established between the 

degradation of the particular structure or component-intended function(s) and the 

parameter(s) being monitored. An example of linking the degradation of a passive 

component-intended function with the performance being monitored is linking the fouling 

of heat exchanger tubes with the heat transfer-intended function as identified by a 

change in the differential temperature across the heat exchanger tubes. This could be 

monitored by periodic heat balances. Since this example deals only with one intended 

function of the tubes (heat transfer), additional programs may be necessary to manage 
A.1-5 

other intended function(s) of the tubes, such as pressure boundary. Thus, a 

performance monitoring program must ensure that the SCs are capable of performing 

their intended functions by using a combination of performance monitoring and 

evaluation (if outside acceptable limits of acceptance criteria) that demonstrate 

that a change in performance characteristic is a result of an age-related 

degradation mechanism. 

4. For prevention or mitigation programs, the parameters monitored should be the specific 

parameters being controlled to achieve prevention or mitigation of aging effects. An 

example is the coolant oxygen level that is being controlled in a water chemistry program 

to mitigate pipe cracking. 

A.1.2.3.4 Detection of Aging Effects 

1. Detection of aging effects should occur before there is a loss of the SC-intended 

function(s). The parameters to be monitored or inspected should be appropriate to 

ensure that the SC-intended function(s) will be adequately maintained for SLR under all 

CLB design conditions. Thus, the discussion for the “detection of aging effects” program 

element should address (a) how the program element would be capable of detecting or 

identifying the occurrence of age-related degradation or an aging effect prior to a loss of 

SC-intended function or (b) for preventive/mitigative programs, how the program would 

be capable of preventing or mitigating their occurrence prior to a loss of a SC-intended 

function. The discussion should provide information that links the parameters to be 

monitored or inspected to the aging effects being managed. 

2. Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth 

principles. A degraded or failed component reduces the reliability of the system, 

challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a 

structure or component should be managed to ensure its availability to perform its 

intended function(s) as designed when called upon. In this way, all system 

level-intended function(s), including redundancy, diversity, and defense-in-depth 

consistent with the plant’s CLB, would be maintained for SLR. A program based solely 

on detecting structure and component failure should not be considered as an effective 

AMP for SLR. 

3. This program element describes “when,” “where,” and “how” program data are collected 

(i.e., all aspects of activities to collect data as part of the program). 

4. For condition monitoring programs, the method or technique (such as visual, volumetric, 

or surface inspection), frequency, and timing of new, one-time inspections may be linked 

to plant-specific or industry-wide OE. The discussion provides justification, including 

codes and standards referenced, that the technique and frequency are adequate to 

detect the aging effects before a loss of SC-intended function. A program based solely 

on detecting SC failures is not considered an effective AMP. 

For a condition monitoring program, when sampling is used to represent a larger 

population of SCs, applicants provide the basis for the inspection population and sample 

size. The inspection population is based on such aspects of the SCs as similarity of 

materials of construction, fabrication, procurement, design, installation, environment, 

operating conditions, and aging effects. The sample size is based on such aspects of the 

SCs as the specific aging effect, location, existing technical information, system and 
A.1-6 

structure design, materials of construction, environment, operating conditions, and 

previous failure history. The samples are biased toward locations most susceptible to the 

specific aging effect of concern in the subsequent period of extended operation. For 

multiunit sites, samples are conducted at all units. Provisions for expanding the sample 

size when degradation is detected in the initial sample are included. 

5. For a performance monitoring program, the “detection of aging effects” program element 

should discuss and establish the monitoring methods that will be used for performance 

monitoring. In addition, the “detection of aging effects” program element should also 

establish and justify the frequency that will be used to implement these performance 

monitoring activities. 

6. For a prevention or mitigation program, the “detection of aging effects” program element 

should discuss and establish the monitoring methods that the program will use to 

monitor for the preventive or mitigative parameters that the program controls and should 

justify the frequency of performing these monitoring activities. 

A.1.2.3.5 Monitoring and Trending 

1. Monitoring and trending activities should be described, and they should provide a 

prediction of the extent of degradation and thus effect timely corrective or mitigative 

actions. Plant-specific and/or industrywide OE may be considered in evaluating the 

appropriateness of the technique and frequency. Results of inspections in the prior 

period of extended operation are used to provide input to trending results. 

2. This program element describes “how” the data collected are evaluated. This includes 

an evaluation of the results against the acceptance criteria. Although aging indicators 

may be quantitative or qualitative, aging indicators should be quantified, to the extent 

possible, to allow trending. The parameter or indicator trended should be described. 

The methodology for analyzing the inspection or test results against the acceptance 

criteria should be described. Trending is a comparison of the current monitoring results 

with previous monitoring results in order to make predictions for the future. 

3. For periodic programs, where practical, identified degradation is projected until the next 

scheduled inspection. The results are evaluated against acceptance criteria to confirm 

that the timing of subsequent inspections maintain the components’ intended functions 

throughout the subsequent period of extended operation based on the projected rate of 

degradation. For sampling-based inspections, results are evaluated against acceptance 

criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain 

the components’ intended functions throughout the subsequent period of extended 

operation based on the projected rate and extent of degradation. 

A.1.2.3.6 Acceptance Criteria 

1. The quantitative or qualitative acceptance criteria of the program and its basis should be 

described. For observed degradation during current inspections, the acceptance criteria, 

against which the need for corrective actions are evaluated, should ensure that the SCintended function(s) are maintained consistent with all CLB design conditions during the 

subsequent period of extended operation. The program should include a methodology 

for analyzing the results against applicable acceptance criteria. 
A.1-7 

2. Where it is practical to project observed degradation to the end of the subsequent period 

of extended operation, the projected degradation is evaluated to determine if it could 

impact the intended function of a system, structure, or component. Additional 

considerations are appropriate for one-time inspections such as whether the projected 

degradation could result in a potential leak. 

3. Acceptance criteria could be specific numerical values, or could consist of a discussion 

of the process for calculating specific numerical values of conditional acceptance criteria 

to ensure that the SC-intended function(s) will be maintained under all CLB design 

conditions. Information from available references may be cited. 

4. It is not necessary to justify any acceptance criteria taken directly from the design basis 

information that is included in the Final Safety Analysis Report, plant Technical 

Specifications, or other codes and standards incorporated by reference into NRC 

regulations; they are a part of the CLB. Nor is it necessary to justify the acceptance 

criteria that have been established in either NRC-accepted or NRC-endorsed 

methodology, such as those that may be given in NRC-approved or NRC-endorsed 

topical reports or NRC-endorsed codes and standards; the acceptance criteria 

referenced in these types of documents have been subject to an NRC review process 

and have been approved or endorsed for their application to an NRC-approved or 

NRC-endorsed evaluation methodology. Also, it is not necessary to discuss CLB design 

loads if the acceptance criteria do not permit degradation because a SC without 

degradation should continue to function as originally designed. Acceptance criteria for 

observed degradation during current inspections, which do permit degradation, are 

based on maintaining the intended function under all CLB design loads. 

A.1.2.3.7 Corrective Actions 

1. Results that do not meet the acceptance criteria are addressed in the applicant’s 

corrective action program under those specific portions of the quality assurance (QA) 

program that are used to meet Criterion XVI, “Corrective Action,” of 10 CFR Part 50, 

Appendix B. Appendix A.2 describes how an applicant may apply its 10 CFR Part 50, 

Appendix B, QA program to fulfill the corrective actions element of this AMP for both 

safety-related and nonsafety-related SCs within the scope of this program. 

2. Actions to be taken when the acceptance criteria are not met should be described in 

appropriate detail or referenced to source documents. Corrective actions, including 

causal evaluations, root cause determination, and prevention of recurrence, should be 

timely. For monitored programmatic parameters that fail to meet defined acceptance 

criteria or standards, corrective action is taken prior to a loss of intended function of the 

affected structure or component. 

3. If corrective actions permit analysis without repair or replacement, the analysis should 

ensure that the SC-intended function(s) are maintained consistent with the CLB. 

4. For plant‐specific programs that rely on NRC‐endorsed TRs, the corrective actions are 

implemented in accordance with corrective actions recommended in the applicable 

reports, or the applicant’s 10 CFR Part 50, Appendix B, QA process, as applicable. 

5. For sampling-based programs, additional inspections are conducted for each inspection 

that did not meet acceptance criteria. The program specifies the number of additional 
A.1-8 

inspections. If subsequent inspections do not meet acceptance criteria, an extent of 

condition and extent of cause analysis is conducted to determine the further extent of 

inspections. 

6. For one-time based programs, when an aging effect identified during an inspection does 

not meet acceptance criteria or projected results of the inspections of a material, 

environment, and aging effect combination does not meet acceptance criteria; a periodic 

inspection program is developed for the specific combination(s) of material, environment, 

and aging effect. 

7. For periodic condition monitoring programs where any projected inspection results will 

not meet acceptance criteria prior to the next scheduled inspection, the bases for the 

inspection frequency are verified and adjusted as necessary. 

A.1.2.3.8 Confirmation Process 

1. The confirmation process should be described. The process ensures that appropriate 

corrective actions have been completed and are effective. 

2. The confirmation process is addressed through those specific portions of the QA program 

that are used to meet Criterion XVI, “Corrective Action,” of 10 CFR Part 50, Appendix B. 

Appendix A.2 describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA 

program to fulfill the confirmation process element of this AMP for both safety-related and 

nonsafety-related systems, structures, and components within the scope of this program. 

3. When significant conditions adverse to quality are identified, there should be follow-up 

activities to confirm that the corrective actions have been completed, a root cause 

determination was performed, and recurrence will be prevented. 

4. For plant‐specific condition monitoring programs that rely on the augmented inspection 

and evaluation methodologies in NRC‐endorsed TRs, the confirmation controls for these 

programs associated with corrective actions are implemented in accordance with the 

existing site 10 CFR 50 Appendix B, QA Programs, or their equivalent, as applicable. 

Additional confirmatory controls may apply as identified in the TRs or in other industry 

reports or guidelines, such as those developed by (but not limited to) Nuclear Energy 

Institute (NEI), the Electric Power Research Institute (EPRI) Boiling Water Reactor Vessel 

and Internals Project (BWRVIP), EPRI Materials Reliability Program (MRP), BWR Owners 

Group, PWR Owners Group, or industry vendors, such as AREVA, Westinghouse, or 

General Electric (GE) or GE-Hitachi. 

A.1.2.3.9 Administrative Controls 

1. The administrative controls of the program should be described. Administrative controls 

provide a formal review and approval process. 

2. Administrative controls are addressed through the QA program that is used to meet the 

requirements of 10 CFR Part 50, Appendix B, associated with managing the effects of 

aging (e.g., document control, special processes, and test control). Appendix A.2 

describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to 

fulfill the administrative controls element of this AMP for both safety-related and 

nonsafety-related SCs within the scope of this program. 
A.1-9 

3. For plant‐specific condition monitoring programs that rely on the augmented inspection 

and evaluation methodologies in NRC‐endorsed TRs, the administrative controls for 

these programs, including their implementing procedures and review and approval 

processes, are implemented in accordance with the existing site 10 CFR 50 Appendix B, 

QA Programs, or their equivalent, as applicable. Additional administrative controls 

criteria may apply as identified in the TRs or in other industry reports or guidelines, such 

as those developed by (but not limited to) NEI, the EPRI BWRVIP, EPRI MRP, BWR 

Owners Group, PWR Owners Group, or industry vendors, such as AREVA, 

Westinghouse, or GE or GE-Hitachi. 

A.1.2.3.10 Operating Experience 

1. Consideration of future plant-specific and industry OE relating to AMPs should be 

discussed (See Appendix A.4). Reviews of OE by the applicant in the future may 

identify areas where AMPs should be enhanced or new programs developed. An 

applicant should commit to a future review of plant-specific and industry OE to confirm 

the effectiveness of its AMPs or indicate a need to develop new AMPs. 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 subsequent period of extended operation. 

2. Currently available OE with existing programs should be discussed. The discussion 

should note any changes to the programs during the first period of extended operation. 

The OE 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 OE should have resulted in 

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 subsequent 

period of extended operation. 

3. Currently available OE, including relevant research and development applicable to new 

programs should also be discussed. For new AMPs that have yet to be implemented at 

an applicant’s facility, the programs have not yet generated any OE. However, there 

may be other relevant plant-specific or generic industry OE that is relevant to the 

program elements, even though the OE 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 OE from implementation of its existing AMPs and 

from generic industry OE. 
A.1-10 

4. For plant‐specific condition monitoring programs that rely on the augmented inspection 

and evaluation methodologies in NRC‐endorsed TRs, the administrative controls for 

dispositioning OE in these programs are implemented in accordance with the existing 

site 10 CFR 50 Appendix B, QA Programs, or their equivalent, as applicable. Additional 

administrative controls criteria may apply as identified in the TRs or in other industry 

reports or guidelines, such as those developed by (but not limited to) NEI, the EPRI 

BWRVIP, EPRI MRP, BWR Owners Group, PWR Owners Group, or industry vendors, 

such as AREVA, Westinghouse, or GE or GE-Hitachi. 

A.1.3 References 

1. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54–The License Renewal Rule.” Revision 6. Agencywide Documents 

Access and Management System (ADAMS) Accession No. ML051860406. 

Washington, DC: Nuclear Energy Institute. June 2005. 

 
A.1-11 

Table A.1-1. Elements of an Aging Management Program for Subsequent 

License Renewal 

Element Description 

1. Scope of Program Scope of program includes the specific SCs subject to an 

AMR for SLR. 

2. Preventive Actions Preventive actions should prevent or mitigate 

aging degradation. 

3. Parameters Monitored or 

Inspected 

Parameters monitored or inspected should be linked to the 

degradation of the particular SC-intended function(s). 

4. Detection of 

Aging Effects 

Detection of aging effects should occur before there is a loss 

of SC-intended function(s). This includes aspects such as 

method or technique (e.g., visual, volumetric, surface 

inspection), frequency, sample size, data collection, and 

timing of new/one-time inspections to ensure timely detection 

of aging effects. 

5. Monitoring and Trending Monitoring and trending should provide predictability of the 

extent of degradation, and timely corrective or 

mitigative actions. 

6. Acceptance Criteria Acceptance criteria, against which the need for corrective 

action will be evaluated, should ensure that the SC-intended 

function(s) are maintained under all CLB design conditions 

during the subsequent period of extended operation. 

7. Corrective Actions Corrective actions, including root cause determination and 

prevention of recurrence, should be timely. 

8. Confirmation Process Confirmation process should ensure that corrective actions 

have been completed and are effective. 

9. Administrative Controls Administrative controls should provide a formal review and 

approval process. 

10. Operating Experience Operating experience applicable to 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 

managed adequately so that the SC-intended function(s) will 

be maintained during the subsequent period of extended 

operation. Operating experience with existing programs 

should be discussed 

In addition, the ongoing review of both plant-specific and 

industry OE, including relevant research and development 

ensures that the AMP is effective in managing the aging 

effects for which it is credited. The AMP is either enhanced or 

new AMPs are developed, as appropriate, when it is 

determined through the evaluation of OE that the effects of 

aging may not be adequately managed.

A.2-1 

A.2 Quality Assurance for Aging Management Programs 

(Branch Technical Position IQMB-1) 

A.2.1 Background 

The subsequent license renewal application is required to demonstrate that the effects of aging on 

structures and components (SCs) subject to an aging management review (AMR) will be 

managed adequately to ensure that their intended functions are maintained consistent with the 

current licensing basis of the facility for the subsequent period of extended operation. Therefore, 

those aspects of the AMR process that affect quality of safety-related systems, structures, and 

components are subject to the quality assurance (QA) requirements of Title 10 of the Code of 

Federal Regulations (10 CFR) Part 50 Appendix B. For nonsafety-related SCs subject to an 

AMR, the existing 10 CFR Part 50 Appendix B QA program may be used by the applicant to 

address the elements of corrective actions, the confirmation process, and administrative controls, 

as described in Branch Technical Position (BTP) RLSB-1 [Appendix A.1 of this Standard Review 

Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

(SRP-SLR)]. The confirmation process ensures that appropriate corrective actions have been 

completed and are effective. Administrative controls should provide for a formal review and 

approval process. Generic Aging Lessons Learned for Subsequent License Renewal 

(GALL-SLR) Report describes how a subsequent license renewal (SLR) applicant can rely on the 

existing requirements in 10 CFR Part 50 Appendix B, “Quality Assurance Criteria for Nuclear 

Power Plants and Fuel Reprocessing Plants,” to satisfy these program elements/attributes. The 

purpose of this BTP (IQMB-1) is to describe an acceptable process for implementing the 

corrective actions, the confirmation process, and administrative controls of aging management 

programs for SLR. 

A.2.2 Branch Technical Position 

1. Safety-related SCs are subject to 10 CFR Part 50 Appendix B requirements, which are 

adequate to address all quality-related aspects of an AMP consistent with the current 

licensing basis (CLB) of the facility for subsequent period of extended operation. 

2. For nonsafety-related SCs that are subject to an AMR for SLR, an applicant has the option 

to expand the scope of its 10 CFR Part 50 Appendix B program to include these SCs and 

to address corrective actions, the confirmation process, and administrative controls for 

aging management during the subsequent period of extended operation. The reviewer 

verifies that the applicant has documented such a commitment in the Final Safety Analysis 

Report supplement in accordance with 10 CFR 54.21(d). 

3. If an applicant chooses an alternative means to address corrective actions, the 

confirmation process, and administrative controls for managing aging of nonsafety-related 

SCs that are subject to an AMR for SLR, the applicant’s proposal is reviewed on a 

case-by-case basis following the guidance in BTP RLSB-1 (Appendix A.1 of this 

SRP-SLR). 

A.2.3 References 

1. 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

2016. 
A.2-2 

2. NRC. NUREG–1800, (Ch. 3.3 – End) “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants.” ADAMS Accession No. ML012070409. 

Washington, DC: U.S. Nuclear Regulatory Commission. July 2001. 
A.3-1 

A.3 Generic Safety Issues Related to Aging 

(Branch Technical Position RLSB-2) 

A.3.1 Background 

Unresolved safety issues (USIs) and generic safety issues (GSIs) are identified and tracked 

in the U.S. Nuclear Regulatory Commission (NRC) formal resolution process set forth in 

NUREG–0933, “Resolution of Generic Safety Issues,” which is updated periodically. Appendix B 

to NUREG–0933 contains a listing of those issues that are applicable to operating and future 

plant. NUREG–0933 is a source of information on generic concerns identified by the NRC. Some 

of these concerns may be related to the effects of aging or time-limited aging analyses (TLAAs) 

for systems, structures, or components within the scope of the subsequent license renewal (SLR) 

review. The purpose of this Branch Technical Position (RLSB-2) is to address the SLR treatment 

of an aging effect or a TLAA which is a subject of an USI or a GSI [60 Federal Register 

(FR) 22484]. 

A.3.2 Branch Technical Position 

A.3.2.1 Treatment of GSIs 

The License Renewal Rule requires that aging effects be managed to ensure that the structures 

and components (SC) intended function(s) are maintained and that TLAAs are evaluated for 

SLR. Thus, all applicable aging effects of SCs subject to an aging management review and all 

TLAAs must be evaluated, regardless of whether they are associated with GSIs or USIs. The 

agency’s Generic Issues Program process for resolving GSIs is described in Management 

Directive 6.4, “Generic Issues Program,” dated January 2, 2015, and SECY-07-0022, “Status 

Report on Proposed Improvements to the Generic Issues Program.” 

A.3.3 References 

1. NRC. NUREG–0933, “Resolution of Generic Safety Issues.” Supplement 34. 

Agencywide Documents Access and Management System (ADAMS) Accession 

No. ML11353A382. Washington, DC: U.S. Nuclear Regulatory Commission. 

December 2011. 

2. NRC. SECY-07-0022, “Status Report on Proposed Improvements to the Generic Issues 

Program.” ADAMS Accession No. ML003744861. Washington, DC: U.S. Nuclear 

Regulatory Commission. January 2007. 

3. NRC. NUREG–1800, (Ch. 3.3 – End) “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants.” ADAMS Accession No. ML012070409. 

Washington, DC: U.S. Nuclear Regulatory Commission. July 2001. 

A.4-1 

A.4 Operating Experience for Aging Management Programs 

A.4.1 Background 

Operating experience is a crucial element of an effective aging management program (AMP). It 

provides the basis to support all other elements of the AMP and, as a continuous feedback 

mechanism, drives changes to these elements to ensure the overall effectiveness of the AMP. 

Operating experience should provide objective evidence to support the conclusion that the effects 

of aging are managed adequately so that the structures and components (SCs)-intended 

function(s) will be maintained during the subsequent period of extended operation. Under their 

current operating licenses, subsequent license renewal (SLR) applicants are required to 

implement programs for the ongoing review of operating experience (OE), such as those 

established in accordance with Item I.C.5, “Procedures for Feedback of Operating Experience to 

Plant Staff,” of NUREG–0737, “Clarification of TMI Action Plan Requirements” (Ref. 3). 

A.4.2 Position 

The systematic review of plant-specific and industry OE, including relevant research and 

development concerning aging management and age-related degradation ensures that the SLR 

AMPs are, and will continue to be, effective in managing the aging effects for which they are 

credited. The AMPs should either be enhanced or new AMPs developed, as appropriate, when it 

is determined through the evaluation of OE that the effects of aging may not be adequately 

managed. AMPs should be informed by the review of OE on an ongoing basis, regardless of the 

AMP’s implementation schedule. 

Acceptable Use of Existing Programs 

Programs and procedures relied upon to meet the requirements of Title 10 of the Code of Federal 

Regulations (10 CFR) Part 50, Appendix B (Ref. 1) and NUREG–0737 (Ref. 3), Item I.C.5, may 

be used for the capture, processing, and evaluation of OE concerning age-related degradation 

and aging management during the term of a renewed operating license. As part of meeting the 

requirements of NUREG–0737, Item I.C.5, the applicant should actively participate in the Institute 

of Nuclear Power Operations’ OE program (formerly the Significant Event Evaluation and 

Information Network (SEEIN) program endorsed in U.S. Nuclear Regulatory Commission (NRC) 

Generic Letter 82-04, “Use of INPO SEEIN Program”) (Ref. 2). These programs and procedures 

may also be used for the translation of recommendations from the OE evaluations into plant 

actions (e.g., enhancement of AMPs and development of new AMPs). While these programs and 

procedures establish a majority of the functions necessary for the ongoing review of OE, they are 

also subject to further review as discussed below. 

Areas of Further Review 

To ensure that the programmatic activities for the ongoing review of OE are adequate for SLR, the 

following points should be addressed: 

 The programs and procedures relied upon to meet the requirements of 10 CFR Part 50, 

Appendix B, and NUREG–0737, Item I.C.5, explicitly apply to and otherwise would not 

preclude the consideration of OE on age-related degradation and aging management. 

Such OE can constitute information on the SCs identified in the integrated plant 

assessment; their materials, environments, aging effects, and aging mechanisms; the 

AMPs credited for managing the effects of aging; and the activities, criteria, and 
A.4-2 

evaluations integral to the elements of the AMPs. To satisfy this criterion, the applicant 

should use the option described in A.2.2.2 of Standard Review Plan for Review of 

Subsequent License Renewal Applications for Nuclear Power Plants Appendix A.2, 

“Quality Assurance for Aging Management Programs (Branch Technical Position 

IQMB-1),” to expand the scope of its 10 CFR Part 50, Appendix B, program to include 

nonsafety-related SCs. 

 The license renewal interim staff guidance documents and revisions to the Generic Aging 

Lessons Learned for Subsequent License Renewal (GALL-SLR) Report should be 

considered as sources of industry OE and evaluated accordingly. There should be a 

process to identify such documents and process them as OE. 

 All incoming plant-specific and industry OE should be screened to determine whether it 

may involve age-related degradation or impacts to aging management activities. 

 A means should be established within the corrective action program to identify, track, and 

trend OE that specifically involves age-related degradation. There should also be a 

process to identify adverse trends and to enter them into the corrective action program 

for-evaluation. 

 Relevant research and development information should be reviewed to determine whether 

it might involve age-related degradation or impacts to aging management activities. 

Relevant foreign and domestic research and development would generally be subject to a 

consensus process, and would have used materials and test conditions typical of 

operating power reactors, including actual operating and environmental conditions. 

Examples of relevant research and development sources are: (a) industry consensus 

standards development organizations (e.g., ASME, IEEE, ACI, API, NACE, International 

Organization for Standardization); (b) Electric Power Research Institute (EPRI); (c) generic 

communications issued by the staff based on research conducted by national labs used by 

the NRC; and (d) NSSS vendor and owner’s groups. 

 Operating experience, including relevant research and development items identified as 

potentially involving aging, should receive further evaluation. This evaluation should 

specifically take into account the following: (a) systems, structures, and components, 

(b) materials, (c) environments, (d) aging effects, (e) aging mechanisms, (f) AMPs, and 

(g) the activities, criteria, and evaluations integral to the elements of the AMPs. The 

assessment of this information should be recorded with the OE evaluation. If it is found 

through evaluation that any effects of aging may not be adequately managed, then a 

corrective action should be entered into the 10 CFR Part 50, Appendix B, program to 

either enhance the AMPs or develop and implement new AMPs. 

 Assessments should be conducted on the effectiveness of the AMPs and activities. These 

assessments should be conducted on a periodic basis that is not to exceed once every 

5 years. They should be conducted regardless of whether the acceptance criteria of the 

particular AMPs have been met. The assessments should also include evaluation of the 

AMP or activity against the latest NRC and industry guidance documents and standards 

that are relevant to the particular program or activity. If there is an indication that the 

effects of aging are not being adequately managed, then a corrective action is entered into 

the 10 CFR Part 50, Appendix B, program to either enhance the AMPs or develop and 

implement new AMPs, as appropriate. 
A.4-3 

 Training on age-related degradation and aging management should be provided to those 

personnel responsible for implementing the AMPs and those personnel who may submit, 

screen, assign, evaluate, or otherwise process plant-specific and industry OE. The scope 

of training should be linked to the responsibilities for processing OE. This training should 

occur on a periodic basis and include provisions to accommodate the turnover of plant 

personnel. 

 Guidelines should be established for reporting plant-specific OE on age-related 

degradation and aging management to the industry. This reporting should be 

accomplished through participation in the Institute of Nuclear Power Operations’ 

OE program. 

 Any enhancements necessary to fulfill the above criteria should be put in place no later 

than the date the renewed operating license is issued and implemented on an ongoing 

basis throughout the term of the renewed license. 

The programmatic activities for the ongoing review of plant-specific and industry experience 

concerning age-related degradation and aging management should be described in the 

subsequent license renewal application, including the Final Safety Analysis Report supplement. 

Alternate approaches for the future consideration of OE are subject to NRC review on a 

case-by-case basis. 

A.4.3 References 

1. 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

2016. 

2. Generic Letter 82-04, “Use of INPO SEE-IN Program.” ADAMS Accession 

No. ML031210688. Washington, DC: U.S. Nuclear Regulatory Commission. 

March 9, 1982. 

3. NUREG–0737, “Clarification of TMI Action Plan Requirements.” Washington, DC: 

U.S. Nuclear Regulatory Commission. November 1980. 

4. NUREG–1801, “Generic Aging Lessons Learned (GALL) Report.” Revision 2. ADAMS 

Accession No. ML103490041. Washington, DC: U.S. Nuclear Regulatory Commission. 

December 2010.