Standard Review Plan for

Review of License Renewal

Applications for Nuclear

Power Plants

Final Report 

Office of Nuclear Reactor Regulation

NUREG-1800, Rev. 2
Standard Review Plan for

Review of License Renewal

Applications for Nuclear

Power Plants

Final Report 

Manuscript Completed: December 2010 

Date Published: December 2010 

Office of Nuclear Reactor Regulation

NUREG-1800, Rev. 2

December 2010 iii NUREG-1800, Rev. 2

ABSTRACT

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

Plants (SRP-LR) provides guidance to 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 Title 10 of the Code of 

Federal Regulations Part 54. The principal purposes of the SRP-LR are to ensure the quality 

and uniformity of staff reviews and to present a well-defined base from which to evaluate 

applicant programs and activities for the period of extended operation. The SRP-LR 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 staff review process. The safety review is based primarily on the 

information provided by the applicant in a license renewal application. Each of the individual 

SRP-LR sections addresses (a) who performs the review, (b) the matters that are reviewed, 

(c) the basis for review, (d) the way the review is accomplished, and (e) the conclusions that are 

drawn. 

December 2010 v NUREG-1800, Rev. 2

TABLE OF CONTENTS

Page

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

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

LIST OF TABLES.........................................................................................................................vii

LIST OF CONTRIBUTORS.......................................................................................................... ix

ABBREVIATIONS.......................................................................................................................xiii

INTRODUCTION ..........................................................................................................................1

CHAPTER 1. ADMINISTRATIVE INFORMATION.....................................................................1-i

1.1 DOCKETING OF TIMELY AND SUFFICIENT RENEWAL APPLICATION.................1.1-1

CHAPTER 2. SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING 

STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW 

AND IMPLEMENTATION RESULTS.........................................................................................2-i

2.1 SCOPING AND SCREENING METHODOLOGY .......................................................2.1-1

2.2 PLANT-LEVEL SCOPING RESULTS.........................................................................2.2-1

2.3 SCOPING AND SCREENING RESULTS: MECHANICAL SYSTEMS .......................2.3-1

2.4 SCOPING AND SCREENING RESULTS: STRUCTURES.........................................2.4-1

2.5 SCOPING AND SCREENING RESULTS: ELECTRICAL AND 

INSTRUMENTATION AND CONTROLS SYSTEMS..................................................2.5-1

CHAPTER 3. AGING MANAGEMENT REVIEW.....................................................................3-i

3.0 INTRODUCTION TO STAFF REVIEW OF AGING MANAGEMENT..........................3.0-1

3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR 

COOLANT SYSTEM ...................................................................................................3.1-1

3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES............................3.2-1

3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS..................................................3.3-1

3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM ..........3.4-1

3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES, AND 

COMPONENT SUPPORTS........................................................................................3.5-1
NUREG-1800, Rev. 2 vi December 2010

3.6 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND 

CONTROLS ................................................................................................................3.6-1

CHAPTER 4 TIME-LIMITED AGING ANALYSES .................................................................4-i

4.1 IDENTIFICATION OF TIME-LIMITED AGING ANALYSES ........................................4.1-1

4.2 REACTOR VESSEL NEUTRON EMBRITTLEMENT ANALYSIS...............................4.2-1

4.3 METAL FATIGUE........................................................................................................4.3-1

4.4 ENVIRONMENTAL QUALIFICATION (EQ) OF ELECTRIC EQUIPMENT.................4.4-1

4.5 CONCRETE CONTAINMENT TENDON PRESTRESS ANALYSIS ...........................4.5-1

4.6 CONTAINMENT LINER PLATE, METAL CONTAINMENTS, AND 

PENETRATIONS FATIGUE ANALYSIS .....................................................................4.6-1

4.7 OTHER PLANT-SPECIFIC TIME-LIMITED AGING ANALYSES................................4.7-1

APPENDIX A BRANCH TECHNICAL POSITIONS................................................................ A-i

A.1 AGING MANAGEMENT REVIEW - GENERIC (BRANCH TECHNICAL 

POSITION RLSB 1) ................................................................................................... A.1-1

A.2 QUALITY ASSURANCE FOR AGING MANAGEMENT PROGRAMS (BRANCH 

TECHNICAL POSITION IQMB-1) .............................................................................. A.2-1

A.3 GENERIC SAFETY ISSUES RELATED TO AGING (BRANCH TECHNICAL 

POSITION RLSB-2) ................................................................................................... A.3-1
December 2010 vii NUREG-1800, Rev. 2

LIST OF TABLES

Page

Table 1.1-1. Acceptance Review Checklist for 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(a). Typical "Passive" Structure-Intended Functions.........................................2.1-17

Table 2.1-4(b). Typical "Passive" Component-Intended Functions.....................................2.1-18

Table 2.1-5. 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........2.2-5

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 3.0-1. FSAR Supplement for Aging Management of Applicable Systems ..............3.0-5

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

Internals, and Reactor Coolant System Evaluated in Chapter IV of the 

GALL Report ..............................................................................................3.1-18

Table 3.1-2. Aging Management Programs Recommended for Reactor Vessel, 

Internals, and Reactor Coolant System......................................................3.1-46

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

Features Evaluated in Chapter V of the GALL Report ...............................3.2-10

Table 3.2-2. Aging Management Programs Recommended for Engineered Safety 

Features .....................................................................................................3.2-23

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

Evaluated in Chapter VII of the GALL Report ............................................3.3-10
NUREG-1800, Rev. 2 viii December 2010

Table 3.3-2. Aging Management Programs Recommended for Aging Management of 

Auxiliary Systems .......................................................................................3.3-40

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

Conversion System Evaluated in Chapter VIII of the GALL Report .............3.4-9

Table 3.4-2. Aging Management Programs Recommended for Aging Management of 

Steam and Power Conversion System.......................................................3.4-22

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

Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report ........................................................................................3.5-18

Table 3.5-2. Aging Management Programs Recommended for Containments, 

Structures, and Component Supports ........................................................3.5-43

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

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

Table 3.6-2. Aging Management Programs Recommended for Electrical and 

Instrumentation and Control Systems ........................................................3.6-16

Table 4.1-1. Sample Process for Potential Time-Limited Aging Analyses and Basis 

for Disposition...............................................................................................4.1-5

Table 4.1-2. Generic Time-Limited Aging Analyses .........................................................4.1-5

Table 4.1-3. Examples of Potential Plant-Specific TLAAs ................................................4.1-6

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

Embrittlement TLAA Evaluation .................................................................4.2-13

Table 4.3-1. Stress Range Reduction Factors................................................................4.3-14

Table 4.3-2. Example of FSAR Supplement for Metal Fatigue TLAA Evaluation...........4.3-14

Table 4.4-1. Environmental Qualification Reanalysis Attributes .......................................4.4-7

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

Electric Equipment TLAA Evaluation............................................................4.4-8

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 .........................4.6-7

Table A.1-1. Elements of an Aging Management Program for License Renewal ............ A.1-9

Table A.3-1. Examples of Generic Safety Issues that Should/Should Not Be 

Specifically Addressed for License Renewal and Basis for Disposition ...... A.3-3
December 2010 ix NUREG-1800, Rev. 2

LIST OF CONTRIBUTORS

Division of License Renewal, Office of Nuclear Reactor Regulation

B. Holian Division Director

M. Galloway Deputy Division Director

S. Lee Deputy Division Director 

L. Lund Deputy Division Director 

R. Auluck Branch Chief

J. Dozier Branch Chief

D. Pelton Branch Chief

A. Hiser Senior Level 

R. Gramm Team Leader

H. Ashar Structural Engineering

M. Banic Mechanical Engineering

A. Buford Structural Engineer

C. Cho Administrative Assistant

J. Davis Materials Engineering

C. Doutt Electrical Engineering

B. Elliot Materials Engineering

A. Erickson General Engineer

S. Figueroa Licensing Assistant

B. Fu Materials Engineering

J. Gavula Mechanical Engineering

W. Holston Mechanical Engineering

E. Keegan Project Manager

I. King Licensing Assistant

R. Li Electrical Engineering

J. Medoff Mechanical Engineering

S. Min Materials Engineering

D. Nguyen Electrical Engineering

V. Perin Mechanical Engineering

A. Prinaris Mechanical Engineering

L. Regner Project Manager

B. Rogers Reactor Engineer

S. Sakai Project Manager

A. Sheikh Structural Engineering

W. Smith Mechanical Engineering

R. Sun Mechanical Engineering

R. Vaucher Mechanical Engineering

A. Wong Mechanical Engineering
NUREG-1800, Rev. 2 x December 2010

C.Y. Yang Materials Engineering

L. Yee Administrative Assistant

O. Yee Mechanical Engineering

Office of Nuclear Reactor Regulation

G. Casto Branch Chief

T. Chan Branch Chief

M. Khanna Branch Chief

A. Klein Branch Chief

T. Lupold Branch Chief

M. Mitchell Branch Chief

R. Taylor Branch Chief

G. Wilson Branch Chief

R. Hardies Senior Level – Materials Engineering

K. Karwoski Senior Level – Steam Generators

K. Manoly Senior Level – Structural Engineering

D. Alley Materials Engineering

J. Bettle Mechanical Engineering

T. Cheng Structural Engineering

G. Cheruvenki Materials Engineering

J. Collins Mechanical Engineering

R. Davis Materials Engineering

S. Gardocki Mechanical Engineering

M. Hartzman Materials Engineering

K. Hoffman Mechanical Engineering

N. Iqbal Fire Protection Engineering

A. Johnson Mechanical Engineering

S. Jones Mechanical Engineering

B. Lee Mechanical Engineering

R. Mathew Electrical Engineering

P. Patniak Mechanical Engineering

G. Perciavello Mechanical Engineering

A. Tsirigotis Mechanical Engineering

M. Yoder Chemical Engineering

E. Wong Chemical Engineering
December 2010 xi NUREG-1800, Rev. 2

Region I

G. Meyer Mechanical Engineering

M. Modes Mechanical Engineering

Office of Nuclear Regulatory Research

A. Csontos Branch Chief

M. Gavrilas Branch Chief

R. Hogan Branch Chief

T. Koshy Branch Chief

M. Salley Branch Chief

R. Tregoning Senior Level – Materials Engineering

S. Aggarwal Electrical Engineering

J. Burke Mechanical Engineering

G. Carpenter Materials Engineering

H. Graves Structural Engineering

A. Hull Materials Engineering

B. Lin Structural Engineering

L. Ramadan Electrical Engineering

G. Stevens Materials Engineering

D. Stroup Fire Protection Engineering

G. Wang Mechanical Engineering

Advanced Technologies and Laboratories International, Inc. (ATL)

K. Makeig Project Manager

K. Chang Mechanical Engineering

O. Chopra Materials Engineering

W. Jackson Mechanical Engineering

D. Jones Programming (Project Enhancement Corp.)

M. May Mechanical Engineering 

A. Ouaou Structural Engineering 

E. Patel Mechanical Engineering

J. Davis Materials Engineering

R. Royal Electrical Engineering

T. Brake Technical Editing

December 2010 xiii NUREG-1800, Rev. 2

ABBREVIATIONS

ACAR aluminum conductor aluminum alloy reinforced

ACSR aluminum conductor steel reinforced

AFW auxiliary feedwater

AMP aging management program

AMR aging management review

ANL Argonne National Laboratory

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transients without scram

B&W Babcock & Wilcox

BWR boiling water reactor

BWRVIP Boiling Water Reactor Vessel and Internals Project

CASS cast austenitic stainless steel

CDF core damage frequency

CE Combustion Engineering

CFR Code of Federal Regulations

CLB current licensing basis

CRD control rod drive

CUF cumulative usage factor

DBA design basis accident

DBE design basis event

DG Draft Regulatory Guide

DLR Division of License Renewal

DOR Division of Operating Reactors

ECCS emergency core cooling system

ECT eddy current testing

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

FAC flow-accelerated corrosion

FR Federal Register

FSAR Final Safety Analysis Report

FSER Final Safety Evaluation Report

GALL Generic Aging Lessons Learned

GE General Electric

GL generic letter

GSI generic safety issue
NUREG-1800, Rev. 2 xiv December 2010

HAZ heat-affected zone

HDPE high-density polyethylene

HELB high-energy line break

HPCI high-pressure coolant injection

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and control

IASCC Irradiation-assisted stress corrosion cracking

IEEE Institute of Electrical and Electronics Engineers

IGA intergranular attack

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

IR insulation resistance

ISI inservice inspection

LCD liquid crystal display

LCO limiting conditions of operation

LED light-emitting diode

LER licensee event report

LOCA loss of coolant accident

LR license renewal

LRA license renewal application

LTOP low-temperature overpressure protection

MEB metal enclosed bus

MIC microbiologically-influenced corrosion

MEAP material/environment/aging effect/program as summarized on AMR lineitems

MRV minimum required value

NDE nondestructive examination

NDT nil-ductility temperature

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NPS nominal pipe size

NRC Nuclear Regulatory Commission

NRR NRC Office of Nuclear Reactor Regulation

NSAC Nuclear Safety Analysis Center

NSR nonsafety-related

NSSS nuclear steam supply system

ODSCC outside diameter stress corrosion cracking

OE operating experience

OM operation and maintenance

OMB Office of Management and Budget
December 2010 xv NUREG-1800, Rev. 2

P&ID piping and instrument diagrams

PLL predicted lower limit

PM Project Manager

PRA probabilistic risk analysis

PT penetrant testing

P-T pressure-temperature

PTLR pressure-temperature limit reports

PTS pressurized thermal shock

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

RCIC reactor core isolation cooling

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG Regulatory Guide

RPV reactor pressure vessel

RT reference temperature

RV reactor vessel

SBO station blackout

SC structures and components

SCC stress corrosion cracking

SER safety evaluation report

SG steam generator

S/G standards and guides

SOC statements of consideration

SOER significant operating experience report

SR safety-related

SR silicon rubber

SRM staff requirements memorandum

SRP standard review plan

SRP-LR standard review plan for license renewal

SS stainless steel

SSC systems, structures, and components

SSE safe shutdown earthquake

TC thermocouples (nozzles)

TLAA time-limited aging analysis

UFSAR updated final safety analysis report

USE upper-shelf energy

USI unresolved safety issue

UT ultrasonic testing

UUSE unirradiated upper-shelf energy

UV ultraviolet

VHP vessel head penetration (nozzles)

WSLR within scope of license renewal
NUREG-1800, Rev. 2 xvi December 2010

XPLE cross-linked polyethylene
December 2010 1 NUREG-1800, Rev. 2

INTRODUCTION

The “Standard Review Plan for Review of License Renewal Applications for Nuclear Power 

Plants” (SRP-LR) provides guidance to 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 (CFR) Part 54. The principal purposes of the SRP-LR are to ensure the 

quality and uniformity of staff reviews and to present a well-defined base from which to evaluate 

applicant programs and activities for the period of extended operation. The SRP-LR 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 staff review process.

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

renewal application (LRA). 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 that each license 

renewal application include an integrated plant assessment (IPA), 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 (FSAR) supplement.

In addition to the technical information required by 10 CFR 54.21, an LRA 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 (a) whether there is reasonable assurance that the activities 

authorized by the renewed license will continue to be conducted in accordance with the CLB 

and (b) 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.

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

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

operation (this determination should be based on the functionality of structures and components 

that are within the scope of license renewal and that require an aging management review) and 

(b) evaluate TLAAs. The LRA is the principal document in which the applicant provides the 

information needed to understand the basis upon which this assurance can be made.

10 CFR 54.21 specifies, in general terms, the technical information to be supplied in the license 

renewal application. NRC Regulatory Guide (RG) 1.188, “Standard Format and Content for 

Applications to Renew Nuclear Power Plant Operating Licenses,” endorses the Nuclear Energy 

Institute (NEI) guidance in NEI 95-10, “Industry Guidelines for Implementing the Requirements 

of 10 CFR Part 54 - The License Renewal Rule.” NEI 95-10 provides guidance on the format 

and content of an LRA. SRP-LR sections are keyed to and numbered according to the section 

numbers in NRC RG 1.188.

During the review of the initial LRAs, NRC staff and the applicants have found that most of the 

programs to manage aging that are credited for license renewal are programs already in use by 

the applicants. In a staff paper (SECY 99-148), “Credit for Existing Programs for License 

Renewal,” dated June 3, 1999, the staff described options and provided a recommendation for 

crediting existing programs to improve the efficiency of the license renewal process. In a staff 

requirements memorandum (SRM) dated August 27, 1999, the NRC approved the staff 

recommendation and directed the staff to focus the review guidance in the SRP-LR on areas 

where existing programs should be augmented for license renewal. Under the terms of the 
NUREG-1800, Rev. 2 2 December 2010

SRM, the SRP-LR references a “Generic Aging Lessons Learned (GALL) Report,” which 

evaluates existing programs generically, to document (a) the conditions under which existing 

programs are considered adequate to manage identified aging effects without change and 

(b) the conditions under which existing programs should be augmented for this purpose.

The GALL Report (NUREG-1801) should be treated as an approved topical report. The NRC 

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

application acceptable with respect to such a matter when the application references the GALL 

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

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

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

evaluated in the GALL Report, if they rely on the report for license renewal.

The SRP-LR is divided into four major chapters: (a) Administrative Information; (b) Scoping and 

Screening Methodology for Identifying Structures and Components Subject to Aging 

Management Review and Implementation Results; (c) Aging Management Review Results; and 

(d) Time-Limited Aging Analyses. The appendices to the SRP-LR list branch technical positions. 

The SRP-LR addresses various site conditions and plant designs and provides complete 

procedures for all of the areas of review pertinent to each of the SRP-LR sections. For any 

specific application, NRC reviewers may select and emphasize particular aspects of each SRPLR section, as appropriate for the application. In some cases, the major portion of the review of 

a plant program or activity may be done 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-LR section in the review of every 

application.

The individual SRP-LR sections address (a) who performs the review, (b) the matters that are 

reviewed, (c) the basis for review, (d) the way the review is accomplished, and (e) the 

conclusions that are sought. One of the objectives of the SRP-LR is to assign review 

responsibilities to the appropriate NRR branches. Each SRP-LR 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 that are assigned these secondary review 

responsibilities also are identified for each SRP-LR section.

Each SRP-LR 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, that is, what is being reviewed by the branch 

that has primary review responsibility. It contains a description of the systems, structures, 

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

renewal application. It also contains a discussion of the information needed or the review 

expected from other branches to permit the primary review branch to complete its review.
December 2010 3 NUREG-1800, Rev. 2

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-LR 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 NUREG-0800, the technical bases for some 

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

are developed and can be included in the SRP-LR.

3. Review Procedures

This subsection discusses the way the review is accomplished. It is generally a step-by-step 

procedure that the reviewer follows to provide reasonable verification that the applicable 

acceptance criteria have been met.

4. Evaluation Findings

This subsection presents the type of conclusion that is sought 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 publish 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, 

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

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

or exemptions from the regulations.

5. Implementation

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

6. References

This subsection lists the references used in the review process.

The SRP-LR incorporates the 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-LR 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 

Director. A revision number and publication date are printed in a lower corner of each page of 

each SRP-LR section. Because individual sections will be revised as needed, the revision 

numbers and dates may not be the same for all sections.

December 2010 1-i NUREG-1800, Rev. 2

CHAPTER 1

ADMINISTRATIVE INFORMATION

December 2010 1.1-1 NUREG-1800, Rev. 2

1.1 DOCKETING OF TIMELY AND SUFFICIENT RENEWAL APPLICATION

Review Responsibilities

Primary - Program responsible for license renewal projects

Secondary - Branches responsible for technical review, as appropriate

1.1.1 Areas of Review

This section addresses (a) the review of the acceptability of a license renewal application for 

docketing in accordance with 10 CFR 2.101 and the requirements of 10 CFR Part 54 and 

(b) whether a license renewal 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 license renewal 

application.

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 reviewers from requesting additional information as the 

review proceeds, nor does it predict 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 the renewal application has been finally determined by the NRC, the 

licensee must continue to perform its activities in accordance with the facility’s current licensing 

basis (CLB), including all applicable license conditions, orders, rules, and regulations.

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

license renewal application are reviewed.

1.1.1.1 Docketing and Sufficiency of Application

The license renewal application 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 a license renewal application is reviewed in accordance with 10 CFR 2.109(b). 

1.1.2 Acceptance Criteria 

1.1.2.1 Docketing/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, and 54.4. A license renewal application is sufficient if it contains the reports, 

analyses, and other documents required in such an application.
NUREG-1800, Rev. 2 1.1-2 December 2010

1.1.2.2 Timeliness of Application

In accordance with 10 CFR 2.109(b), a license renewal application is timely if it is submitted at 

least 5 years before the expiration of the current operating license (unless an exemption is 

granted) and if it is determined to be sufficient.

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 docketing of a sufficient renewal application is made 

only after a formal license renewal application 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 license renewal, the reviewer should determine 

whether the applicant has made a reasonable effort to provide the required administrative, 

technical, and environmental information (Ref. 1). 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 II in the checklist addresses timeliness of the application.

Items II.1 through II.3, III, and IV in the checklist address technical information, the Final Safety 

Analysis Report (FSAR) supplement, and technical specification changes, respectively. 

Chapters 2, 3, and 4 of the standard review plan for license renewal (SRP-LR) 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 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 staff 

should review 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. 2). The 

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

consistent with the requirements of 10 CFR Part 51. 

 
December 2010 1.1-3 NUREG-1800, Rev. 2

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 staff and the applicant) to the applicant should clearly state that (a) the application 

is not sufficient and is not acceptable for docketing and (b) 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 staff begins its 

technical review. For license renewal applications, 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 VI 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 staff and the 

applicant) to the applicant should clearly state that (a) the application is not timely, (b) the 

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

the expiration date. However, if the application is otherwise determined to be acceptable for 

docketing, the technical review can begin.
NUREG-1800, Rev. 2 1.1-4 December 2010

1.1.4 Evaluation Findings

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

satisfy the provisions outlined here. Depending on the results of this review, one of the following 

conclusions is included in the staff’s letter to the applicant:

• On the basis of its review, as discussed above, the 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 

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 staff has determined that the 

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

1.1.5 Implementation

Except for cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of NRC regulations, the methods described herein are used 

by NRC staff members in their evaluation of conformance with NRC regulations.

1.1.6 References

1. NRC Regulatory Guide 1.188, “Standard Format and Content for Applications to Renew 

Nuclear Power Plant Operating Licenses,” U.S. Nuclear Regulatory Commission, January 

2005. 

2. NUREG-1555, “Standard Review Plans for Environmental Reviews for Nuclear Power 

Plants,” Supplement 1, “Operating License Renewal,” U.S. Nuclear Regulatory Commission, 

October 1999.
December 2010 1.1-5 NUREG-1800, Rev. 2

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

for Docketing 

Yes No

I. General Information

1. Application identifies specific unit(s) applying for 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. Signed original application and 13 copies are provided to 

the Document Control Desk. One copy is provided to the 

appropriate Regional office [10 CFR 50.4(b)(3)]

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 foreignowned 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
NUREG-1800, Rev. 2 1.1-6 December 2010

Yes No

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)]

II. Technical Information

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

consists of:

A. For those SSCs within the scope of license renewal [10 CFR 

54.4], identification and listing of those structures and 

components 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 subject to an AMR. For 

commodity groups, description of basis for the grouping

b. Lists of structures and components subject to an AMR 

B. Description and justification of methods used to identify 

structures and components 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 structures 

and components

b. Identification of applicable aging effects based on 

materials, environment, operating experience, etc.

c. Identification and description of aging management 

programs

d. Demonstration of aging management provided

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

and consists of:

A. Listing of plant-specific TLAAs in accordance with the six 

criteria specified in 10 CFR 54.3 [10 CFR 54.21(c)(1)]

B. 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 period of 

extended operation are provided [10 CFR 54.21(c)(2)]
December 2010 1.1-7 NUREG-1800, Rev. 2

Yes No

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 period of extended 

operation [10 CFR 54.21(c)(2)] 

III. An FSAR supplement [10 CFR 54.21(d)] is provided and contains 

the following information:

1. Summary description of the aging management programs 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

December 2010 2-i NUREG-1800, Rev. 2

CHAPTER 2

SCOPING AND SCREENING METHODOLOGY FOR 

IDENTIFYING STRUCTURES AND COMPONENTS 

SUBJECT TO AGING MANAGEMENT REVIEW AND 

IMPLEMENTATION RESULTS

December 2010 2.1-1 NUREG-1800, Rev. 2

2.1 SCOPING AND SCREENING METHODOLOGY

Review Responsibilities

Primary – Assigned branch

Secondary – None

2.1.1 Areas of Review

This section addresses the scoping and screening methodology for license renewal. As required 

by 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 on 10 CFR 54.4, and meet two criteria:

1. They perform such functions without moving parts or without a change in configuration 

or properties, as set forth in 10 CFR 54.21(a)(1)(i) (denoted as “passive” components 

and structures in this SRP), and

2. They are not subject to replacement based on a qualified life or specified time period, as 

set forth in 10 CFR 54.21(a)(1)(ii) (denoted as “long-lived” structures and components).

The identification of the SSCs within the scope of license renewal is called “scoping.” For those 

SSCs within the scope of license renewal, the identification of “passive,” “long-lived” structures 

and components that are subject to an AMR is called “screening.”

To verify that the applicant has properly implemented its methodology, the 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 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; and
NUREG-1800, Rev. 2 2.1-2 December 2010

• 10 CFR 54.21(a)(1) and (a)(2) as they relate to the methods utilized by the applicant to 

identify plant structures and components 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 NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 - The License Renewal Rule” (Ref. 1), 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 

Regulatory Guide 1.188.

2.1.3 Review Procedures

Preparation for the review of the scoping and screening methodology employed by the applicant 

should include the following:

• Review of the NRC’s safety evaluation report (SER) that was issued along with the 

operating license for the facility. 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). 

• Review of 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 

Regulatory Guide 1.29, “Seismic Design Classification” (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).

• Review of 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 design basis events (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 design basis events as defined in the rule is not limited to Chapter 15 (or 

equivalent) of the UFSAR. Examples of design basis events that may not be described 

in this chapter include external events, such as floods, storms, earthquakes, tornadoes, 
December 2010 2.1-3 NUREG-1800, Rev. 2

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

regarding design basis events as defined in 10 CFR 50.49(b)(1) may be found in any 

chapter of the facility UFSAR, the Commission’s regulations, NRC orders, exemptions, 

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

systems, structures, and components that are relied upon to remain functional during 

and following design basis events (as defined in 10 CFR 50.49(b)(1)) to ensure the 

functions described in 10 CFR 54.4(a)(1).

• Review of 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 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 aging management review by helping to draw 

attention to specific vulnerabilities (e.g., results of an IPE or 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.

• Review of the results of the facility’s Individual Plant Examination of External Events 

(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. 

• Review of 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” [applicable 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,” and

(e) 10 CFR 50.63, “Loss of All Alternating Current Power” (applicable to PWR 

plants).

Other staff members are 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 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 license 

renewal project manager.

2.1.3.1 Scoping

Once the information delineated above has been gathered, the reviewer reviews the applicant’s 

methodology to determine whether its depth and breadth are sufficiently comprehensive to 

identify the SSCs within the scope of license renewal, and the structures and components 
NUREG-1800, Rev. 2 2.1-4 December 2010

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 defining functional 

requirements for facility SSCs that make up an applicant’s CLB should be considered as the 

initial input into the scoping process. 10 CFR 50.49 defines DBEs as conditions of normal 

operation, including anticipated operational occurrences, 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 (SR) 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 systems, 

structures, and components 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 technical specifications, the NRC states (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 technical specifications and applicable limiting 

conditions of operation when scoping for license renewal. This is not to say that the events and 

functions addressed within the applicant’s technical specifications can be excluded in 

determining the SSCs within the scope of license renewal solely on the basis of such an event’s 

inclusion in the technical specifications. Rather, those SSCs governed by an applicant’s 

technical specifications 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 license renewal.

For licensee commitments, such as licensee responses to NRC Bulletins, GLs, or enforcement 

actions, and those documented in staff safety evaluations or licensee event reports, and which 

make up the remainder of an applicant’s CLB, many of the associated SSCs need not be 

considered under license renewal. 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 system, 

structure, or component necessary to fulfill the requirement of a particular regulation, order, 

license condition, and/or exemption may need to be considered when scoping for license 
December 2010 2.1-5 NUREG-1800, Rev. 2

renewal. For example, NRC Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification,” 

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 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 license renewal.

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 license renewal.

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).

Table 2.1-2 contains specific staff guidance on certain subjects of scoping.

2.1.3.1.1 Safety-Related

The applicant’s methodology is reviewed to ensure that the SR 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:

• 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.
NUREG-1800, Rev. 2 2.1-6 December 2010

2.1.3.1.2 Nonsafety-Related

The applicant’s methodology is reviewed to ensure that nonsafety-related (NSR) 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 license renewal. 

The scoping criterion under 10 CFR 54.4(a)(2), in general, is intended to identify those NSR 

SSCs that support SR functions. More specifically, this scoping criterion requires an applicant to 

identify all NSR 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:

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. [...] 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 NSR SSCs (including certain second-, third-, or fourth-level support systems) whose 

failures are considered in the CLB and could prevent the satisfactory accomplishment of an SR 

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, and (3) industrywide operating experience 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 NSR 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 license 

renewal. By letters dated December 3, 2001 and March 15, 2002, the NRC issued a staff 

position to NEI which provided 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 operating experience which 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”] 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. 
December 2010 2.1-7 NUREG-1800, Rev. 2

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),” further 

described the staff’s recommendations for the evaluation of non-piping SSCs to determine 

which additional NSR SSCs are within scope. 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 operating experience. The paper further 

describes operating experience as all documented plant-specific and industrywide experience 

that can be used to determine the plausibility of a failure. Documentation would include NRC 

generic communications and event reports, plant-specific condition reports, industry reports,

such as significant operating experience reports (SOERs), 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 SR portion 

of the pipe as being within the scope of license renewal 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 SR 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 NSR piping up to its anchors and (2) 

the associated piping anchors as being within the scope of license renewal 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 NSR piping attached directly to SR piping (within scope) 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 which 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 structures and components that are part of 

the NSR piping segment boundary up to and including the anchor point or equivalent anchor 

point within scope of the rule.

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 NSR piping and associated structures 

and components attached to SR piping is included in scope up to a boundary point which 

encompasses at least two (2) supports in each of three (3) orthogonal directions.

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, environmental qualification, pressurized thermal shock (PTS), anticipated 
NUREG-1800, Rev. 2 2.1-8 December 2010

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 “[a]ll structures, 

systems, and components relied on in safety analyses or plant evaluations to perform a function 

that demonstrates compliance with the [specified] Commission regulations. . .” 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 that this [referring to 10 CFR 54.4(a)(3)] scoping 

category include all SSC whose function is relied upon to demonstrate 

compliance with these Commission[ ] regulations. An applicant for license 

renewal should rely on the plant’s current licensing bases, actual plant-specific 

experience, industrywide operating experience, as appropriate, and existing 

engineering evaluations to determine those SSC that are the initial focus of 

license renewal review.

Therefore, all SSCs that are relied upon in the plant’s CLB (as defined in 10 CFR 54.3), plantspecific 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 

an NSR 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 license renewal 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 

within the scope of the rule under 10 CFR 54.4(a)(3). For example, if an NSR 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) non-seismically-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 
December 2010 2.1-9 NUREG-1800, Rev. 2

plant evaluations) that is specifically relied upon for compliance with the applicable NRC 

regulation. For example, if analysis of an NSR 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). 

The PTS regulation is applicable only to PWRs. If the renewal application is for a PWR and the 

applicant relies on a Regulatory Guide 1.154 (Ref. 5) analysis to satisfy 10 CFR 50.61, as 

described in the plant’s CLB, the reviewer verifies that the applicant’s methodology would 

include SSCs relied on in that analysis.

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 Regulatory Guide 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 staff's review is based on the plant-specific current 

licensing basis, regulatory requirements, and offsite power design configurations.

2.1.3.2 Screening

Once the SSCs within the scope of license renewal have been identified, the next step is 

determining which structures and components are subject to an AMR (i.e., “screening”) (Ref. 1).

Table 2.1-3 contains specific staff guidance on certain subjects of screening.

2.1.3.2.1 “Passive”

The reviewer reviews the applicant’s methodology to ensure that “passive” structures and 

components 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 structures and components that do 

not display “a change in state.” 10 CFR 54.21(a)(1)(i) provides specific examples of structures 

and components that do or do not meet the criterion. The reviewer verifies that the applicant’s 

screening methodology includes consideration of the intended functions of structures and

components consistent with the plant’s CLB, as typified in Tables 2.1-4(a) and (b), respectively 

(Ref. 1).

The license renewal rule focuses on “passive” structures and components because structures 

and components that have passive functions generally do not have performance and condition 

characteristics that are as readily observable as those that perform active functions. “Passive” 

structures and components, for the purpose of the license renewal rule, are those that perform 
NUREG-1800, Rev. 2 2.1-10 December 2010

an intended function, as described in 10 CFR 54.4, without moving parts or without a change in 

configuration or properties (Ref. 2). The description of “passive” may also be interpreted to 

include structures and components that do not display “a change of state.”

Table 2.1-5 provides a list of typical structures and components 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 

structures and components listed in Table 2.1-5 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” structures and components 

are identified as those that are not subject to periodic replacement based on a qualified life or 

specified time period. Passive structures and components 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” structures 

and components:

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 

(Ref. 3).

Structures and components 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 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 
December 2010 2.1-11 NUREG-1800, Rev. 2

justification in a license renewal application that a replacement program on the 

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 license renewal 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 staff’s safety 

evaluation report:

On the basis of its review, as discussed above, the staff concludes that there is 

reasonable assurance that the applicant’s methodology for identifying the 

systems, structures, and components within the scope of license renewal and the 

structures and components requiring an aging management review is consistent 

with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).

2.1.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of NRC regulations, the method described herein will be used 

by the staff in its evaluation of conformance with NRC regulations (Ref. 6-12 as examples).

2.1.6 References

1. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.

2. Regulatory Guide 1.29, Rev. 3, “Seismic Design Classification,” U.S. Nuclear Regulatory 

Commission, March 2007.

3. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.

4. Generic Letter (GL) 88-20, “Individual Plant Examination for Severe Accident Vulnerabilities10 CFR 50.54(f),” dated November 23, 1988.

5. Regulatory Guide 1.154, “Format and Content of Plant-Specific Pressurized Thermal Shock 

Safety Analysis Reports for Pressurized Water Reactors,” January 1987.

6. NUREG-1723, “Safety Evaluation Report Related to the License Renewal of Oconee 

Nuclear Stations, Units 1, 2, and 3,” March 2000.

7. Letter to Douglas J. Walters, Nuclear Energy Institute, from Christopher I. Grimes, NRC, 

dated August 5, 1999.

8. Summary of December 8, 1999, Meeting with the Nuclear Energy Institute (NEI) on License 

Renewal Issue (LR) 98-12, “Consumables,” Project No. 690, January 21, 2000.
NUREG-1800, Rev. 2 2.1-12 December 2010

9. Letter to William R. McCollum, Jr., Duke Energy Corporation, from Christopher I. Grimes, 

NRC, dated October 8, 1999.

10. Letter to Alan Nelson, Nuclear Energy Institute, and David Lochbaum, Union of Concerned 

Scientists, from Christopher I. Grimes, NRC, “License Renewal Issue: Scoping of Seismic 

II/I Piping Systems,” dated December 3, 2001.

11. Letter to Alan Nelson, Nuclear Energy Institute, and David Lochbaum, Union of Concerned 

Scientists, from Christopher I. Grimes, NRC, “License Renewal Issue: Guidance on the 

Identification and Treatment of Structures, Systems, and Components Which Meet 10 CFR 

54.4(a)(2),” dated March 15, 2002.

12. Letter to Alan Nelson, Nuclear Energy Institute, and David Lochbaum, Union of Concerned 

Scientists, from Christopher I. Grimes, NRC, “Staff Guidance on Scoping of Equipment 

Relied on to Meet the Requirements of the Station Blackout (SBO) Rule (10 CFR 50.63) for 

License Renewal (10 CFR 54.4(a)(3)),” dated April 1, 2002.
December 2010 2.1-13 NUREG-1800, Rev. 2

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
NUREG-1800, Rev. 2 2.1-14 December 2010

Table 2.1-2 Specific Staff Guidance on Scoping

Issue Guidance

Commodity 

groups

The applicant may also group like structures and components into 

commodity groups. Examples of commodity groups are pipe supports and 

cable trays. The basis for grouping structures and components can be 

determined by such characteristics as similar function, similar design, similar 

materials of construction, similar aging management practices, or similar 

environments. If the applicant uses commodity groups, the reviewer verifies 

that the applicant has described the basis for the groups.

Complex 

assemblies

Some structures and components, 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. 10), 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 44o

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 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 
December 2010 2.1-15 NUREG-1800, Rev. 2

Table 2.1-2 Specific Staff Guidance on Scoping

Issue Guidance

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 aging management review: 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 operating 

experience, and (3) industrywide operating experience 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 (Ref. 7).

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 (Ref. 7).
NUREG-1800, Rev. 2 2.1-16 December 2010

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: (a) packing, gaskets, component seals, and Orings; (b) structural sealants; (c) oil, grease, and component filters; and (d) 

system filters, fire extinguishers, fire hoses, and air packs. The consumables 

in both categories (a) and (b) 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 (a), the applicant would generally 

be able to exclude these subcomponents using a clear basis, such as the 

example of ASME Section III not being relied on for pressure boundary. For 

category (b), 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 (c) 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 (d) 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) (Ref. 8).

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 (Ref. 9).

Multiple 

functions

Structures and components may have multiple functions. The intended 

functions as delineated in 10 CFR 54.4(b) are to be reviewed for license 

renewal. 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.
December 2010 2.1-17 NUREG-1800, Rev. 2

Table 2.1-4(a) 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 high-energy line breaks (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.
NUREG-1800, Rev. 2 2.1-18 December 2010

Table 2.1-4(b) 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

Insulate (electrical) Insulate and support an electrical conductor

Filter Provide filtration

Heat Transfer Provide heat transfer

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 safetyrelated and/or nonsafety-related components

Throttle Provide flow restriction
December 2010 2.1-19 NUREG-1800, Rev. 2

Table 2.1-5 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 License Renewal

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
NUREG-1800, Rev. 2 2.1-20 December 2010

Table 2.1-5 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)

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

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

Pressurizers Yes

33 Non-Class I Piping 

Components

Underground Piping Yes

34 Non-Class I Piping 

Components

Piping in Low Temperature 

Demineralized Water Service

Yes

35 Non-Class I Piping 

Components

Piping in High Temperature Single 

Phase Service

Yes

36 Non-Class I Piping 

Components

Piping in Multiple Phase Service Yes

37 Non-Class I Piping 

Components

Service Water Piping Yes
December 2010 2.1-21 NUREG-1800, Rev. 2

Table 2.1-5 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)

38 Non-Class I Piping 

Components

Low Temperature Gas Transport 

Piping

Yes

39 Non-Class I Piping 

Components

Stainless Steel Tubing Yes

40 Non-Class I Piping 

Components

Instrument Tubing Yes

41 Non-Class I Piping 

Components

Expansion Joints Yes

42 Non-Class I Piping 

Components

Ductwork Yes

43 Non-Class I Piping 

Components

Sprinkler Heads Yes

44 Non-Class I 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)

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 HVAC Coolers (including housings) Yes
NUREG-1800, Rev. 2 2.1-22 December 2010

Table 2.1-5 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)

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

71 Miscellaneous 

Process Components

Restricting Orifices Yes

72 Miscellaneous 

Process Components

Air Compressor No

73 Electrical and I&C Alarm Unit (e.g., fire detection 

devices)

No

74 Electrical and I&C Analyzers (e.g., gas analyzers, 

conductivity analyzers)

No
December 2010 2.1-23 NUREG-1800, Rev. 2

Table 2.1-5 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)

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, 

nonsegregated-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

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
NUREG-1800, Rev. 2 2.1-24 December 2010

Table 2.1-5 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)

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

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
December 2010 2.1-25 NUREG-1800, Rev. 2

Table 2.1-5 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)

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

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
NUREG-1800, Rev. 2 2.1-26 December 2010

Table 2.1-5 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)

102 Electrical and I&C Switches (e.g., differential pressure 

indicating switches, differential 

pressure switches, pressure indicator 

switches, pressure switches, flow 

switches, conductivity switches, levelindicating switches, temperatureindicating 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

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)
December 2010 2.1-27 NUREG-1800, Rev. 2

Table 2.1-5 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)

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

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

December 2010 2.2-1 NUREG-1800, Rev. 2

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 license renewal. 10 CFR 54.21(a)(1) 

requires the applicant to identify and list structures and components subject to an aging 

management review (AMR). These are “passive,” “long-lived” structures and components that 

are within the scope of license renewal. In addition, 10 CFR 54.21(a)(2) requires the applicant to 

describe and justify the methods used to identify these structures and components. The 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 license renewal. 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 license renewal. 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 license renewal, as defined in 10 CFR 54.4(a). This is “scoping” of the plantlevel systems and structures for license renewal. To verify that the applicant has properly 

implemented its methodology, the 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 

license renewal.

Examples of plant systems are the reactor coolant, containment spray, standby gas treatment 

(BWR), emergency core cooling, open and closed cycle cooling water, compressed air, 

chemical and volume control (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 structures and components that are “passive” and “long-lived,” in accordance with 

10 CFR 54.21(a)(1)(i) and (ii). These “passive,” “long-lived” structures and components are 

those that are subject to an AMR. The staff reviews these results separately following the 

guidance in Sections 2.3 through 2.5.
NUREG-1800, Rev. 2 2.2-2 December 2010

The applicant has the flexibility to determine the set of systems and structures it considers as 

within the scope of license renewal, provided that this set includes the systems and structures 

that the NRC has determined are within the scope of license renewal. Therefore, the reviewer 

need not review all systems and structures that the applicant has identified to be within the 

scope of license renewal because the applicant has the option to include more systems and 

components than those defined to be within the scope of license renewal 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 License Renewal

The reviewer verifies the applicant’s identification of plant-level systems and structures that are 

within the scope of license renewal.

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 license renewal in 

accordance with NRC regulations in 10 CFR 54.4. For the applicant’s implementation of its 

methodology to be acceptable, the staff should have reasonable assurance that there has been 

no omission of plant-level systems and structures within the scope of license renewal.

2.2.2.1 Systems and Structures within the Scope of License Renewal

Systems and structures are within the scope of license renewal 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), PTS (10 CFR 50.61), ATWS 

(10 CFR 50.62), and SBO (10 CFR 50.63).

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 license renewal 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 staff to make its safety finding. In addition, 
December 2010 2.2-3 NUREG-1800, Rev. 2

other staff members review the applicant’s scoping and screening methodology separately 

following the guidance in Section 2.1. The reviewer should keep these other 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 license renewal 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 License Renewal

The reviewer determines whether the applicant has properly identified the plant-level systems 

and structures within the scope of license renewal by reviewing selected systems and structures 

that the applicant did not identify as being within the scope of license renewal 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 structures, systems, 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 license renewal 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 license renewal. The review of individual portions of systems and 

structures that are within the scope of license renewal 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 license renewal (54.4) and subject to aging management review 

(54.21(a)(1)). The reviewer should sample selected systems and structures that the applicant 

did not identify as within the scope of license renewal 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 license renewal. 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 license 

renewal. 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” (Ref. 1).

• The applicant does not identify the fire protection pump house as within the scope of 

license renewal. 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 license renewal 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.
NUREG-1800, Rev. 2 2.2-4 December 2010

Table 2.2-1 contains additional examples based on lessons learned from the review of the initial 

license renewal applications, including a discussion of the plant-specific determination of 

whether a system or structure is within the scope of license renewal.

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 license renewal. 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 license renewal, the staff 

would have reasonable assurance that the applicant has identified the systems and structures 

within the scope of license renewal.

If the reviewer determines that the applicant has satisfied the criteria described in this review 

section, the staff would have reasonable assurance that the applicant has identified the systems 

and structures within the scope of license renewal. 

2.2.4 Evaluation Findings

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the SRP-LR, then the 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 staff concludes that there is 

reasonable assurance that the applicant has appropriately identified the systems 

and structures within the scope of license renewal in accordance with 10 CFR 

54.4.

2.2.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specific portions of NRC regulations, the method described herein will be used 

by the staff in its evaluation of conformance with NRC regulations.

2.2.6 References

1. Regulatory Guide 1.29, Rev. 3, “Seismic Design Classifications,” U.S. Nuclear Regulatory 

Commission, March 2007.
December 2010 2.2-5 NUREG-1800, Rev. 2

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 safetyrelated 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 license renewal 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 safetyrelated 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 license renewal.

December 2010 2.3-1 NUREG-1800, Rev. 2

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 license 

renewal. 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).

10 CFR 54.21(a)(1) requires an applicant to identify and list structures and components subject 

to an aging management review (AMR). These are “passive,” “long-lived” structures and 

components that are within the scope of license renewal (WSLR). In addition, 10 CFR 

54.21(a)(2) requires an applicant to describe and justify the methods used to identify these 

structures and components. The 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 staff focuses its review on the implementation results. Such a focus allows the 

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 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 WSLR, as defined in 

10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for license renewal. 

The 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 license renewal, 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 identify these particular portions of the system in marked-up 
NUREG-1800, Rev. 2 2.3-2 December 2010

piping and instrument diagrams (P&IDs) or in other media. This is “scoping” of mechanical 

components in a system to identify those that are WSLR for a system.

For those identified mechanical components that are WSLR, 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 structures and components for which an 

AMR is performed, provided that this set includes the structures and components for which the 

NRC has determined that an AMR is required. This is based on the Statements of Consideration 

(SOC) 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 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 License Renewal

Mechanical components are WSLR as delineated in 10 CFR 54.4(a) if they are

• Safety-related structures, systems, or 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).

• 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), PTS (10 CFR 50.61), ATWS (10 CFR 

50.62), and SBO (10 CFR 50.63).

2.3.2.2 Components Subject to an Aging Management Review

Mechanical components are subject to an AMR if they are WSLR and perform an intended 

function as defined in 10 CFR 54.4(b) without moving parts or a change in configuration or 
December 2010 2.3-3 NUREG-1800, Rev. 2

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 WSLR 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 staff to make its safety finding. In 

addition, other staff members review the applicant’s scoping and screening methodology 

separately, following the guidance in Section 2.1. The reviewer should keep these other 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 license renewal project 

manager.

For each area of review, the following review procedures are to be followed.

2.3.3.1 Components within the Scope of License Renewal

In this step, the staff determines whether the applicant has properly identified the components 

that are WSLR. The Rule requires applicants to identify components that are WSLR and subject 

to an AMR. In the past, LRAs have included a table of components that are WSLR; that 

information need not be submitted with future LRAs. Although a list of WSLR components will 

be available at plant sites for inspection, the reviewer should determine through sampling of 

P&IDs, and review of UFSAR and other plant documents, what portion of the components are 

within scope. The reviewer should check to see if any components exist that the staff believes 

are within scope 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 

WSLR, especially the license renewal 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 WSLR 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.

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, 
NUREG-1800, Rev. 2 2.3-4 December 2010

the reviewer should identify, to the extend practical, the system functions of the piping runs and 

components that are identified as not being WSLR 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 WSLR, the reviewer would have reasonable assurance that the applicant has 

identified the components WSLR for the mechanical systems.

Table 2.3-1 provides examples of mechanical components scoping lessons learned from the 

review of the initial license renewal 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 which are WSLR (i.e., those identified in 

Subsection 2.3.3.1). The reviewer should review selected components that the applicant has 

identified as WSLR 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 WSLR 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 

2.1-5 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 WSLR at their 

facility and is listed as “passive” on Table 2.1-5. Although Table 2.1-5 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 WSLR. 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 2.1-5 indicates that air compressors are not subject to an AMR, the reviewer should find 

the applicant’s determination acceptable.

Section 2.1 contains additional guidance on screening the following:

• Consumables

• Heat exchanger-intended functions

• Multiple functions
December 2010 2.3-5 NUREG-1800, Rev. 2

If the reviewer does not identify any omissions of components from those that are subject to an 

AMR, the 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 license renewal 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 componentintended functions.

2.3.4 Evaluation Findings

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the SRP-LR, then the 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 staff concludes that there is 

reasonable assurance that the applicant has appropriately identified the 

mechanical system components within the scope of license renewal, as required 

by 10 CFR 54.4, and that the applicant has adequately identified the system 

components subject to an aging management review in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specific portions of NRC regulations, the method described herein will be used 

by the staff in its evaluation of conformance with NRC regulations.

2.3.6 References

None. 
NUREG-1800, Rev. 2 2.3-6 December 2010

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 WSLR.

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 design basis event. 

Thus, this ductwork is not WSLR.

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 WSLR.

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 WSLR.

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 plantspecific basis.
December 2010 2.3-7 NUREG-1800, Rev. 2

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 license renewal 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 

structures and components 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.
NUREG-1800, Rev. 2 2.3-8 December 2010

Table 2.3-3 Examples of Mechanical Component-Intended Functions

Component Intended Functiona

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

a 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 boundaryintended function, but may not have a heat transfer function. Similarly, not all orifices have 

flow restriction as an intended function.
December 2010 2.4-1 NUREG-1800, Rev. 2

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 license renewal. 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 HVAC ducting supports);

• Nonsafety-related structures whose failure could prevent safety-related structures, 

systems, and components (SSCs) from performing their intended functions (that is, 

seismic Category II over I structures).

Typical structural components include the following: liner plates, walls, floors, roofs, foundations, 

doors, beams, columns, and frames.

10 CFR 54.21(a)(1) requires an applicant to identify and list structures and components subject 

to an aging management review (AMR). These are “passive,” “long-lived” structures and 

components that are within the scope of license renewal (WSLR). In addition, 10 CFR 

54.21(a)(2) requires an applicant to describe and justify the methods used to identify these 

structures and components. The 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 staff focuses its review on the implementation results. Such a focus allows the 

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 staff has the basis to find that there is 

reasonable assurance that the applicant has identified the structural 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 WSLR, as defined in 

10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for license renewal. 

The staff reviews the applicant’s plant-level “scoping” results separately following the guidance 

in Section 2.2.

For structures that are WSLR, an applicant must identify the structural components that are 

“passive” and “long-lived” in accordance with 10 CFR 54.21(a)(1)(i) and (ii). These “passive,” 

“long-lived” structural components are those that are subject to an AMR (“screening”). The 

applicant’s methodology implementation results for identifying structural components subject to 

an AMR is the area of review.
NUREG-1800, Rev. 2 2.4-2 December 2010

The applicant has the flexibility to determine the set of structures and components for which an 

AMR is performed, provided that this set includes the structures and components 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 structural components than those 

subject to an AMR, pursuant to 10 CFR 54.21(a)(1). Rather, the reviewer should focus on those 

structural components 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 staff should have 

reasonable assurance that there has been no omission of structural components that are 

subject to an AMR.

2.4.2.1 Structural Components Subject to an Aging Management Review

Structural components are WSLR 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), PTS (10 CFR 50.61), ATWS (10 CFR 

50.62), and SBO (10 CFR 50.63).

Structural components are subject to an AMR if they are WSLR 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 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 WSLR 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 staff to make its safety finding. In addition, 
December 2010 2.4-3 NUREG-1800, Rev. 2

other staff members review the applicant’s scoping and screening methodology separately 

following the guidance in Section 2.1. The reviewer should keep these other 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 license renewal 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 License Renewal

In this step, the staff determines which structures and structural components are WSLR. The 

Rule requires applicants to identify structures that are subject to an AMR, but not structures that 

are WSLR. Whereas, in the past, LRAs have included a table of structures that are WSLR, that 

information need not be submitted with future LRAs. Although that information will be available 

at plant sites for inspection, the reviewer should determine through sampling of P&IDs and 

through review of the UFSAR and other plant documents what portion of the components are 

within scope. The reviewer should check to see if any structures exist that the staff believes are 

within scope 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 “longlived”).

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 WSLR. For each of the plant-level structures WSLR, an applicant should 

identify those structural components that have intended functions. For example, the applicant 

may identify that its auxiliary building is WSLR. 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 

WSLR at its facility and is listed as “passive” on Table 2.1-5. Although Table 2.1-5 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 WSLR. 

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 WSLR and subject to an 

AMR.

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 WSLR. For example, for a building WSLR, 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 II over I” concern in accordance with the plant’s CLB. The 

reviewer need not verify all structural components that have been identified as subject to an 
NUREG-1800, Rev. 2 2.4-4 December 2010

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 WSLR. 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 

the unresolved safety issue, USI A-46 (Ref. 1), the reviewer should verify that the structure or 

component has been included WSLR.

The applicant should also identify the intended functions of structural components. Table 2.1-4 

provides typical “passive” structural component-intended functions. 

The 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 others 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 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 AMPs.

If the reviewer determines that the applicant has satisfied the criteria described in this review 

section, the staff would have reasonable assurance that the applicant has identified the 

components that are WSLR and subject to an AMR.

2.4.4 Evaluation Findings

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the SRP-LR, then the 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 staff concludes that there is 

reasonable assurance that the applicant has appropriately identified the 
December 2010 2.4-5 NUREG-1800, Rev. 2

structural components subject to an aging management review in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.4.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specific portions of NRC regulations, the method described herein will be used 

by the staff in its evaluation of conformance with NRC regulations.

2.4.6 References

1. NUREG-1211, "Regulatory Analysis for Resolution of Unresolved Safety Issue A-46, 

`Seismic Qualification of Equipment in Operating Plants,'" U.S. Nuclear Regulatory 

Commission, February 1987.

2. NUREG-0933, "Resolution of Generic Safety Issues,” Supplement 32, U.S. Nuclear 

Regulatory Commission, August 2008.
NUREG-1800, Rev. 2 2.4-6 December 2010

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 safetyrelated 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 WSLR. 

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 WSLR.

Water-stops Ground water leakage into the auxiliary building could 

occur as a result of degradation to the water-stops. This 

leakage may cause flooding of equipment WSLR. (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.
December 2010 2.5-1 NUREG-1800, Rev. 2

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 controls (I&C) 

scoping and screening results for license renewal. Typical electrical and I&C components that 

are subject to an aging management review (AMR) for license renewal include electrical cables 

and connections.

10 CFR 54.21(a)(1) requires an applicant to identify and list structures and components subject 

to an AMR. These are “passive,” “long-lived” structures and components that are within the 

scope of license renewal (WSLR). In addition, 10 CFR 54.21(a)(2) requires an applicant to 

describe and justify the methods used to identify these structures and components. The 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 staff focuses its review on the 

implementation results. Such a focus allows the 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 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 DBEs 

considered in the plant’s 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 WSLR, as defined in 10 CFR 54.4(a). This is “scoping” of the 

plant-level systems and structures for license renewal. The staff reviews the applicant’s plantlevel “scoping” results separately following the guidance in Section 2.2.

For an electrical and I&C system that is WSLR, 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 license renewal. 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 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 
NUREG-1800, Rev. 2 2.5-2 December 2010

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.

10 CFR 54.21(a)(1)(i) provides many examples of electrical and I&C components that are not 

considered to be “passive” and are not subject to an AMR for license renewal. 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 

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 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 License Renewal

Electrical and I&C components are WSLR 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), PTS (10 CFR 50.61), ATWS (10 CFR 

50.62), and 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:
December 2010 2.5-3 NUREG-1800, Rev. 2

• The onsite power system meeting the requirements under 10 CFR 54.4(a)(1) (safetyrelated systems)

• Equipment that is required to cope with an SBO (e.g., alternate ac power sources) 

meeting the requirements under 10 CFR 54.4(a)(3)

• The plant system portion of the offsite power system that is used to connect the plant to 

the offsite power source meeting the requirements under 10 CFR 54.4(a)(3). The 

electrical distribution equipment out to the first circuit breaker with the offsite distribution 

system (i.e., equipment in the switchyard). This path typically includes the circuit 

breakers that connect to the offsite system power transformers (startup transformers), 

the transformers themselves, the intervening overhead or underground circuits between 

circuit breaker and transformer and transformer and onsite electrical distribution system, 

and the associated control circuits and structures. However, the staff's review is based 

on the plant-specific current licensing basis, regulatory requirements, and offsite power 

design configurations.

2.5.2.2 Components Subject to an Aging Management Review

Electrical and I&C components are subject to an AMR if they are WSLR 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 WSLR 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 staff to make its safety finding. In 

addition, other staff members review the applicant’s scoping and screening methodology 

separately following the guidance in Section 2.1. The reviewer should keep these other 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 license renewal project 

manager.

The reviewer should verify that an applicant has identified in the license renewal 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 “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.

The scope of 10 CFR 50.49 electric equipment to be included within 10 CFR 54.4(a)(3) is that 

“long-lived” (qualified life of 40 years or greater) equipment already identified by licensees under 

10 CFR 50.49(b), which specifies certain electric equipment important to safety. Licensees may 

rely upon their listing of environmental qualification equipment, as required by 10 CFR 50.49(d), 

for the purposes of satisfying 10 CFR 54.4(a)(3) with respect to equipment 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 environmental qualification (10 CFR 50.49). 
NUREG-1800, Rev. 2 2.5-4 December 2010

Environmental qualification equipment is not limited to “passive” equipment. The applicant may 

identify environmental qualification equipment separately for TLAA evaluation and not include 

such equipment as subject to an AMR under 10 CFR 54.21(a)(1). The environmental 

qualification equipment identified for TLAA evaluation would include the “passive” environmental 

qualification equipment subject to an AMR. The TLAA evaluation would ensure that the 

environmental qualification equipment would be functional for the period of extended operation. 

The staff reviews the applicant’s environmental qualification 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 License Renewal

In this step, the staff determines whether the applicant has properly identified the components 

that are WSLR. The Rule requires that the LRA identify and list components that are WSLR and 

are subject to an AMR. Whereas, in the past, LRAs have included a table of components that 

are WSLR, generally that information need not be submitted with future LRAs. 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 UFSAR and other plant documents, what 

portion of the components are WSLR. The reviewer must check to see if any components exist 

that the 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 license renewal. 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 WSLR. 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 WSLR. 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 

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 WSLR 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:
December 2010 2.5-5 NUREG-1800, Rev. 2

• Commodity groups

• Complex assemblies

• Scoping events

• Hypothetical failure

• Cascading

If the reviewer does not identify any omissions of components from those that are WSLR, the 

staff would have reasonable assurance that the applicant has identified the components WSLR 

for the electrical and I&C systems.

2.5.3.2 Component 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 WSLR (i.e., those identified in 

Subsection 2.5.3.1). The reviewer should review selected components that the applicant has 

identified as being WSLR 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 2.1-5 lists 

many typical components and structures, and their associated intended functions, and identifies 

whether they are “passive.” The reviewer should use Table 2.1-5 in identifying whether certain 

components are “passive.” The reviewer should verify that electrical and I&C components 

identified as “passive” in Table 2.1-5 have been included by the applicant as being subject to an 

AMR. Although Table 2.1-5 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 staff would have reasonable assurance that the applicant has identified the 

components subject to an AMR for the electrical and I&C systems.

2.5.4 Evaluation Findings

If the reviewer determines that the applicant has provided information sufficient to satisfy the 

provisions of the SRP-LR, then the 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 staff concludes that there is 

reasonable assurance that the applicant has appropriately identified the electrical and 

instrumentation and controls system components subject to an aging management review 

in accordance with the requirements stated in 10 CFR 54.21(a)(1).
NUREG-1800, Rev. 2 2.5-6 December 2010

2.5.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specific portions of NRC regulations, the method described herein will be used 

by the staff in its evaluation of conformance with NRC regulations.

2.5.6 References

1. SAND96-0344, “Aging Management Guideline for Commercial Nuclear Power PlantsElectrical Cable and Terminations,” Sandia National Laboratories, September 1996, 

page 6-11.
December 2010 2.5-7 NUREG-1800, Rev. 2

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 WSLR.

This is acceptable, and a staff 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 WSLR.

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 WSLR 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 WSLR.

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.

December 2010 3-i NUREG-1800, Rev. 2

CHAPTER 3

AGING MANAGEMENT REVIEW 

December 2010 3.0-1 NUREG-1800, Rev. 2

3.0 INTRODUCTION TO STAFF REVIEW OF AGING MANAGEMENT

The NRC project manager (PM) responsible for the safety review of the license renewal 

application (LRA) is responsible for assigning to appropriate NRC Office of Nuclear Reactor 

Regulation (NRR) divisions the review or audit of aging management reviews (AMRs) of 

systems, structures, and components or aging management programs (AMPs) identified in the 

applicant’s LRA. 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 (SRP-LR, NUREG-1800) for review of license renewal applications, as 

directed by the scope of each of these sections. 

Review of the AMPs requires assessment of ten program elements as defined in this SRP-LR. 

The NRC division assigned the AMP reviews the ten program elements to verify their technical 

adequacy. For three of the ten program elements (corrective actions, confirmation process, and 

administrative controls), the NRC division responsible for review of the quality assurance 

aspects of the application verifies that the applicant has documented a commitment in the 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 requests that 

the Division responsible for quality assurance review the applicant’s proposal on a case-specific 

basis. Table 3.0-1 is a supplement to the FSAR and contains a list of programs that are 

applicable to each SRP-LR section and sub-section. It also contains the programs that are used 

to manage the aging effects associated with various systems.

3.0.1 Background on the Types of Reviews 

10 CFR 54.21(a)(3) requires that the LRA demonstrate, for systems, structures, and 

components (SSCs) within the scope of license renewal and subject to an AMR pursuant to 10 

CRF 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 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-LR describe how the AMRs and AMPs are reviewed. One 

method that the applicant may use to conduct its AMRs is to satisfy the NUREG-1801 (GALL 

Report) recommendations. The applicant may choose to use methodology other than that in the 

GALL Report to demonstrate compliance with 10 CFR 54.21(a)(3).

The GALL Report is a technical basis document to the SRP-LR, which provides the staff with 

guidance in reviewing a license renewal application. An applicant may reference the GALL 

Report in a license renewal application to demonstrate that the programs at the applicant’s 

facility correspond to those reviewed and approved in the GALL Report. The GALL Report 

(NUREG-1801) should be treated as an approved topical report. However, if an applicant takes 

credit for a program in the GALL Report, it is incumbent on the applicant to ensure that the 

conditions and operating experience at the plant is bounded by the conditions and operating 

experience for which the GALL 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 aging management program(s) in the GALL Report as appropriate.
NUREG-1800, Rev. 2 3.0-2 December 2010

The staff will verify that the applicant’s programs are consistent with those described in the 

GALL report and/or with plant conditions and operating experience during the performance of an 

aging management program audit and review. The focus of the balance of the staff review of a 

license renewal application is on those programs that an applicant has enhanced to be 

consistent with the GALL Report, those programs for which the applicant has taken an 

exception to the program described in the GALL Report, and plant-specific programs not 

described in the GALL Report.

If an applicant takes credit for a program in the GALL Report, it is incumbent on the applicant to 

ensure that the plant program contains all the elements of the referenced GALL Report 

program. In addition, the conditions at the plant must be bounded by the conditions for which 

the GALL Report program was evaluated. The above verifications must be documented onsite 

in an auditable form. The applicant should include a certification in the license renewal 

application that the verifications have been completed and are documented onsite in an 

auditable form. 

The GALL Report contains one acceptable way to manage aging effects for license renewal. An 

applicant may propose alternatives for staff review in its plant-specific license renewal 

application. Use of the GALL Report is not required, but its use should facilitate both preparation 

of a license renewal application by an applicant and timely, uniform review by the NRC staff. 

In addition, the GALL Report does not address scoping of structures and components for 

license renewal. Scoping is plant-specific, and the results depend on the plant design and 

current licensing basis. The inclusion of a certain structure or component in the GALL Report

does not mean that this particular structure or component is within the scope of license renewal 

for all plants. Conversely, the omission of a certain structure or component in the GALL Report 

does not mean that this particular structure or component is not within the scope of license 

renewal for any plants.

The GALL Report contains an evaluation of a large number of structures and components that 

may be in the scope of a typical LRA. The evaluation results documented in the GALL Report 

indicate that many existing, typical generic aging management programs are adequate to 

manage aging effects for particular structures or components for license renewal without 

change. The GALL Report also contains recommendations on specific areas for which generic 

existing programs should be augmented for license renewal and documents the technical basis 

for each such determination. In addition, the GALL Report identifies certain SSCs that may or 

may not be subject to particular aging effects, and for which industry groups are developing 

generic aging management programs or investigating whether aging management is warranted. 

To the extent that the ultimate generic resolution of such an issue will need NRC review and 

approval for plant-specific implementation, as indicated in a plant-specific FSAR supplement, 

and reflected in the SER associated with a particular LR application, an amendment pursuant to 

10 CFR 50.90 will be necessary.

In this SRP-LR, 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 

NRC’s regulations in 10 CFR 54.21. Subsection 3.X.3 presents the review procedures to be 

followed. Some rows (items) in the AMR tables (in Chapters II through VIII of the GALL Report) 

establish the need to perform “further evaluations.” This can be clearly seen in Tables 3.X-1, 

and the last two columns (for 2010 and 2005, respectively) denoted the Rev2 and Rev1 AMR 

Line Item references. The acceptance criteria for satisfying these “further evaluations” are found 

in Subsections 3.X.2.2. The related review procedures are provided in subsections 3.X.3.2.
December 2010 3.0-3 NUREG-1800, Rev. 2

In Regulatory Guide 1.188, “Standard Format and Content for Applications to Renew Nuclear 

Power Plant Operating Licenses,” the NRC has endorsed an acceptable methodology for 

applicants to structure license renewal applications. Using the guidance described in the 

aforementioned Regulatory Guide, the applicant documents in the LRA whether its AMR item is 

consistent or not consistent with the GALL Report. 

A portion of the AMR includes the assessment of the AMPs in the GALL Report. The applicant 

may choose to use an AMP that is consistent with the GALL Report AMP, or may choose a 

plant-specific AMP. 

If a GALL Report AMP is selected to manage aging, the applicant may take one or more 

exceptions to specific GALL Report AMP program elements. However, any deviation or 

exception to the GALL Report AMP should be described and justified. Exceptions are portions 

of the GALL Report AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not currently meet 

all the program elements defined in the GALL Report AMP. If this is the situation, the applicant 

makes a commitment to augment the existing program to satisfy the GALL Report AMP 

elements prior to the period of extended operation. This commitment is an AMP “enhancement.”

Enhancements are revisions or additions to existing aging management programs that the 

applicant commits to implement prior to the period of extended operation. Enhancements 

include, but are not limited to, those activities needed to ensure consistency with the GALL 

Report recommendations. Enhancements may expand, but not reduce, the scope of an AMP. 

An audit and review is conducted at the applicant’s facility to evaluate AMPs that the applicant 

claims to be consistent with the GALL Report. Reviews are performed to address those AMRs 

or AMPs related to emergent issues, stated to be not consistent with the GALL Report, or based 

on an NRC-approved precedent (e.g., AMRs and AMPs addressed in an NRC SER of a 

previous LRA). As a result of the criteria established in 10 CFR Part 54, the guidance provided 

in SRP-LR, GALL Report, Regulatory Guide 1.188, and the applicant’s exceptions and/or 

enhancements to a GALL Report AMP, the following types of AMRs and AMPs are audited or 

reviewed by the NRC staff. 

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL Report AMPs

• Plant-specific AMPs

FSAR Supplement

• Each LRA AMP will provide an FSAR Supplement which defines changes to the FSAR 

that will be made as a condition of a renewed license. This FSAR Supplement defines 

the aging management programs the applicant is crediting to satisfy 10 CFR 54.21(a)(3).

• The FSAR Supplement should also contain a commitment to implement the LRA AMP 

enhancement prior to the period of extended operation.
NUREG-1800, Rev. 2 3.0-4 December 2010

3.0.2 Applications with Approved Extended Power Uprates

Extended power uprates (EPU) 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 (ADAMS Accession 

ML042790085), the NRC Executive Director for Operation states that “All license renewal 

applications with an approved EPU will be required to perform an operating experience review 

and its impact on [aging] management programs for structures, and components before entering 

the period of extended operation.” One way for an applicant with an approved EPU to satisfy 

this criterion is to document its commitment to performing an operating experience review and 

its impact on aging management programs for systems, structures, and components (SSCs) 

before entering the period of extended operation as part of its license renewal application. Such 

licensee commitments should be documented in the NRC staff’s SER, written in support of 

issuing a renewed license. The 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 license renewal review. If necessary, the PM 

assigns a responsible group to address EPU.

NOTE: In the Summary of Aging Management review tables, the Component field provides a 

description of the component, material, and environment combinations for which the GALL 

Report recommends a specified aging management program to manage the related aging 

effect/mechanism. To provide SRP-LR tables in a format most useful to the reviewer and 

industry, the presentation and specific language describing structure/components, materials, 

aging effects/mechanisms, and supplemental information supporting the aging management 

programs may vary somewhat between chapters. Tables 3.3-1, 3.4-1, and 3.6-1 exhibit similar 

language while Tables 3.1-1 and 3.5-1 exhibit language that varies somewhat. Also note that 

the capitalization and punctuation scheme in these Tables 3.X-1 can seem variable, the SRPLR component column is an artifact of how material and component information has been 

consolidated in this report. This is not a technical difference, but one that supports the 

presentation of the materials in the desired table format. When in doubt, refer back to the 

specified “Rev2 Item,” the AMR Item(s) upon which a given row is based.
December 2010 3.0-5 NUREG-1800, Rev. 2

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

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XI.E1

Insulation Material for 

Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements

The program consists of accessible electrical cables 

and connections installed in adverse localized 

environments to be visually inspected at least once 

every 10 years for cable jacket and connection 

insulation surface anomalies, such as embrittlement, 

discoloration, cracking, melting, swelling, or surface 

contamination, that could indicate incipient conductor 

insulation aging degradation from temperature, 

radiation, or moisture.

First inspection for 

license renewal 

completed prior to 

the period of 

extended 

operation

G

XI.E2

Insulation Material for 

Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits

The program calls for the review of calibration results 

or findings of surveillance tests on electrical cables 

and connections used in circuits with sensitive, highvoltage, low-level current signals, such as radiation 

monitoring and nuclear instrumentation, to provide an 

indication of the existence of aging effects based on 

acceptance criteria related to instrumentation circuit 

performance. By reviewing the results obtained 

during normal calibration or surveillance, an applicant 

may detect severe aging degradation prior to the loss 

of the cable and connection intended function. The 

review of calibration results or findings of surveillance 

tests is performed at least once every 10 years.

In cases where cables are not included as part of 

calibration or surveillance program testing circuit, a 

proven cable test (such as insulation resistance 

tests, time domain reflectometry tests, or other 

testing judged to be effective in determining cable 

system insulation condition as justified in the 

application) is performed. The test frequency is 

based on engineering evaluation and is at least once 

every 10 years.

First review of 

calibration results 

or findings of 

surveillance test 

results or cable 

tests for license 

renewal 

completed prior to 

the period of 

extended 

operation

G

XI.E3

Inaccessible Power 

Cables Not Subject to 10 

CFR 50.49 Environmental 

The program calls for inaccessible or underground 

(e.g. in conduit, duct bank, or direct buried) power 

First tests or first 

inspections for 

license renewal G
NUREG-1800, Rev. 2 3.0-6 December 2010

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

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Qualification 

Requirements

(greater than or equal to 400 volts) cables exposed 

to significant moisture, to be tested at least once 

every 6 years to provide an indication of the condition 

of the conductor insulation. The specific type of test 

to be used should be capable of detecting reduced 

insulation resistance of the cable’s insulation system 

due to wetting or submergence. The applicant can 

assess the condition of the cable insulation with 

reasonable confidence using one or more of the 

following techniques: Dielectric Loss (Dissipation 

Factor/Power Factor), AC Voltage Withstand, Partial 

Discharge, Step Voltage, Time Domain 

Reflectometry, Insulation Resistance and 

Polarization Index, Line Resonance Analysis, or 

other testing that is state-of-the-art at the time the 

tests are performed. One or more tests are used to 

determine the condition of the cables so they will 

continue to meet their intended function during the 

period of extended operation.

The inspection frequency for water collection is 

established and performed based on plant-specific 

operating experience with cable wetting or 

submergence in manholes (i.e., the inspection is 

performed periodically based on water accumulation 

over time and event driven occurrences such as 

heavy rain or flooding). The periodic inspection 

should occur at least annually. The inspection should 

include direct observation that cables are not wetted 

or submerged, that cables/splices and cable support 

structures are intact, and dewatering/drainage 

systems (i.e., sump pumps) and associated alarms 

operate properly. In addition, operation of dewatering 

devices should be inspected and operation verified 

prior to any known or predicted heavy rain or flooding 

completed prior to 

the period of 

extended 

operation
December 2010 3.0-7 NUREG-1800, Rev. 2

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

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events. 

XI.E4 Metal Enclosed Bus 

The program calls for the visual inspection of metal 

enclosed bus (MEB) internal surfaces to detect agerelated degradation, including cracks, corrosion, 

foreign debris, excessive dust buildup, and evidence 

of moisture intrusion. MEB insulating material is 

visually inspected for signs of embrittlement, 

cracking, chipping, melting, swelling, discoloration, or 

surface contamination, which may indicate 

overheating or aging degradation. The internal bus 

insulating supports are visually inspected for 

structural integrity and signs of cracks. MEB external 

surfaces are visually inspected for loss of material 

due to general, pitting, and crevice corrosion. 

Accessible elastomers (e.g., gaskets, boots, and 

sealants) are inspected for degradation, including 

surface cracking, crazing, scuffing, and changes in 

dimensions (e.g., “ballooning” and “necking”), 

shrinkage, discoloration, hardening and loss of 

strength. A sample of accessible bolted connections 

is inspected for increased resistance of connection 

by using thermography or by measuring connection 

resistance using a micro-ohmmeter. These 

inspections are performed at least once every 10 

years.

As an alternative to thermography or measuring 

connection resistance of accessible bolted 

connections covered with heat shrink tape, sleeving, 

insulating boots, etc., the applicant may use visual 

inspection of insulation material to detect surface 

anomalies, such as embrittlement, cracking, 

chipping, melting, discoloration, swelling, or surface 

contamination. When this alternative visual 

inspection is used to check bolted connections, the 

First inspection for 

license renewal 

completed prior to 

the period of 

extended 

operation

G
NUREG-1800, Rev. 2 3.0-8 December 2010

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

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first inspection is completed prior to the period of 

extended operation and every 5 years thereafter.

XI.E5 Fuse Holders 

The program consists of fuse holders within the 

scope of license renewal to be tested at least once 

every 10 years to provide an indication of the 

condition of the metallic clamp portion of the fuse 

holders. Testing may include thermography, contact 

resistance testing, or other appropriate testing 

methods.

First tests for 

license renewal 

completed prior to 

the period of 

extended 

operation

G

XI.E6

Electrical Cable 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements

The program consists of a representative sample of 

electrical connections within the scope of license 

renewal, which is tested at least once prior to the 

period of extended operation to confirm that there are 

no aging effects requiring management during that 

period. Testing may include thermography, contact 

resistance testing, or other appropriate testing 

methods without removing the connection insulation, 

such as heat shrink tape, sleeving, insulating boots, 

etc. The one-time test provides additional 

confirmation to support industry operating experience 

that shows that electrical connections have not 

experienced a high degree of failures and that 

existing installation and maintenance practices are 

effective. 

As an alternative to thermography or measuring 

connection resistance of the cable connection

sample, for the accessible cable connections that are 

covered with heat shrink tape, sleeving, insulating 

boots, etc., the applicant may use visual inspection of 

insulation materials to detect surface anomalies, 

such as embrittlement, cracking, chipping, melting, 

discoloration, swelling, or surface contamination. 

When this alternative visual inspection is used to 

check cable connections, the first inspection is 

First tests for 

license renewal 

completed prior to 

the period of 

extended 

operation

G
December 2010 3.0-9 NUREG-1800, Rev. 2

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

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completed prior to the period of extended operation 

and every 5 years thereafter.

XI.M1

ASME Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD

The program consists of periodic volumetric, surface, 

and/or visual examination of American Society of 

Mechanical Engineers (ASME) Class 1, 2, and 3 

pressure-retaining components, including welds, 

pump casings, valve bodies, integral attachments, 

and pressure-retaining bolting for assessment, signs 

of degradation, and corrective actions. This program 

is in accordance with the ASME Code Section XI 

edition and addenda approved in accordance with

provisions of 10 CFR 50.55a during the period of 

extended operation. 

Existing program G

G

XI.M2 Water Chemistry 

This program mitigates aging effects of loss of 

material due to corrosion, cracking due to stress 

corrosion cracking (SCC) and related mechanisms, 

and reduction of heat transfer due to fouling in 

components exposed to a treated water environment. 

Chemistry programs are used to control water 

chemistry for impurities (e.g., chloride, fluoride, and 

sulfate) that accelerate corrosion. This program relies 

on monitoring and control of water chemistry to keep 

peak levels of various contaminants below the 

system-specific limits, based on Electric Power 

Research Institute (EPRI) guidelines (a) BWRVIP190 (EPRI 1016579, BWR Water Chemistry 

Guidelines – 2008 Revision) for BWRs or (b) EPRI 

1014986 (PWR Primary Water Chemistry – Revision 

6) and EPRI 1016555 (PWR Secondary Water 

Chemistry – Revision 7) for pressurized water 

reactors (PWRs). 

Existing program

G

G

G

G

G
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XI.M3 Reactor Head Closure 

Stud Bolting

This program includes (a) ISI in conformance with 

the requirements of the ASME Code, Section XI, 

Subsection IWB, Table IWB-2500-1, and (b) 

preventive measures to mitigate cracking. The 

program also relies on recommendations to address 

reactor head stud bolting degradation as delineated 

in NUREG-1339 and NRC Regulatory Guide (RG) 

1.65.

Existing program G

XI.M4 BWR Vessel ID 

Attachment Welds

The program includes (a) inspection and flaw 

evaluation in conformance with the guidelines of 

staff-approved BWRVIP-48-A to ensure the longterm integrity and safe operation of boiling water 

reactor (BWR) vessel internal components.

Existing program G

XI.M5 BWR Feedwater Nozzle

This program includes (a) enhancing ISI specified in 

the ASME Code, Section XI, with the 

recommendation of General Electric (GE) NE-523-

A71-0594 to perform periodic ultrasonic testing 

inspection of critical regions of the BWR feedwater 

nozzle. 

Existing program G

XI.M6 BWR Control Rod Drive 

Return Line Nozzle 

The program includes mandatory in-service 

inspection in accordance with ASME Code Section 

XI, Subsection IWB, Table IWB 2500-1 and 

augmented ISI examinations in accordance with the

applicant’s commitments to Generic Letter 80-095 to 

implement the recommendations in NUREG-0619. 

Program should 

be implemented 

prior to period of 

extended 

operation

G

XI.M7 BWR Stress Corrosion 

Cracking

The program to manage intergranular stress 

corrosion cracking (IGSCC) in stainless steel or 

nickel alloy BWR coolant pressure boundary piping 

is delineated in NUREG-0313, Rev. 2, and NRC 

Generic Letter (GL) 88-01 and its Supplement 1. 

The program includes (a) preventive measures to 

mitigate IGSCC and (b) inspection and flaw 

evaluation to monitor IGSCC and its effects.

Existing program

G

G

G

XI.M8 BWR Penetrations The program includes inspection and flaw evaluation Existing program
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in conformance with the guidelines of staff-approved 

boiling water reactor vessel and internals project 

documents BWRVIP-47-A, BWRVIP-49-A, and 

BWRVIP-27-A, to ensure the long-term integrity and 

safe operation of BWR vessel internal components. 

G

XI.M9 BWR Vessel Internals

The program includes inspection and flaw evaluation 

in conformance with the guidelines of applicable and 

staff-approved BWRVIP documents, and to ensure 

the long-term integrity and safe operation of BWR 

vessel internal components.

This program also consists of (1) determination of 

the susceptibility of cast austenitic stainless steel 

components, (2) accounting for the synergistic effect 

of thermal aging and neutron irradiation, and (3) 

implementing a supplemental examination program, 

as necessary.

This program also addresses aging degradation of 

X-750 alloy and precipitation-hardened (PH) 

martensitic stainless steel (e.g., 15-5 and 17-4 PH 

steel) materials and martensitic stainless steel (e.g., 

403, 410, 431 steel) that are used in BWR vessel 

internal components.

Existing program G

XI.M10 Boric Acid Corrosion

The program consists of (a) visual inspection of 

external surfaces that are potentially exposed to 

borated water leakage, (b) timely discovery of leak 

path and removal of the boric acid residues, 

(c) assessment of the damage, and (d) follow-up 

inspection for adequacy. This program is 

implemented in response to NRC GL 88-05 and 

recent operating experience.

Existing program

G

G

G

G

G
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G

XI.M11B

Cracking of Nickel-Alloy 

Components and Loss of 

Material due to Boric AcidInduced Corrosion in

Reactor Coolant Pressure 

Boundary Components 

(PWRS only)

This program addresses cracking of nickel-alloy 

components and loss of material due to boric acidinduced corrosion in susceptible, safety-related 

components in the vicinity of nickel-alloy reactor 

coolant pressure boundary components. It provides 

(a) inspection requirements for the PWR vessel, 

steam generator, pressurizer components, and 

piping if they contain the primary water stress 

corrosion cracking (PWSCC) susceptible materials 

designated alloys 600/82/182 and (b) inspection 

requirements for reactor pressure vessel upper 

heads.

Program should 

be implemented 

prior to period of 

extended 

operation

G

XI.M12

Thermal Aging 

Embrittlement of Cast 

Austenitic Stainless Steel 

(CASS) 

The program consists of the determination of the 

susceptibility of CASS piping, piping components, 

and piping elements in PWR emergency core cooling 

system (ECCS) systems, including interfacing pipe 

lines to the chemical and volume control system and 

to the spent fuel pool; and in BWR ECCS systems,

including interfacing pipe lines to the suppression 

chamber and to the drywell and suppression 

chamber spray system in regard to thermal aging 

embrittlement based on the casting method, 

molybdenum content, and ferrite percentage. For 

potentially susceptible piping, aging management is 

accomplished either through enhanced volumetric 

examination or component-specific flaw tolerance 

evaluation.

Existing program

G

G

XI.M16A PWR Vessel Internals

The program relies on implementation of the EPRI

Report No. 1016596 (MRP-227) and EPRI Report 

No. 1016609 (MRP-228) to manage the aging effects 

on the reactor vessel internal components. 

This program is used to manage (a) various forms of 

Program should 

be implemented 

prior to period of 

extended 

operation

G
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cracking, including SCC, PWSCC, irradiationassisted stress corrosion cracking (IASCC), or 

cracking due to fatigue/cyclical loading; (b) loss of 

material induced by wear; (c) loss of fracture 

toughness due to either thermal aging or neutron 

irradiation embrittlement; (d) dimensional changes 

and potential loss of fracture toughness due to void 

swelling and irradiation growth; and (e) loss of 

preload due to thermal and irradiation-enhanced 

stress relaxation or creep.

XI.M17 Flow-Accelerated 

Corrosion (FAC) 

The program consists of (a) conducting appropriate 

analysis and baseline inspections, (b) determining 

the extent of thinning and replacement/repair of 

components, and (c) performing follow-up 

inspections to confirm or quantify and take long-term 

corrective actions. The program relies on 

implementation of EPRI guidelines of NSAC-202L-R2 

or R3.

Existing program

G

G

G

XI.M18 Bolting Integrity 

This program focuses on closure bolting for 

pressure-retaining components and relies on 

recommendations for a comprehensive bolting 

integrity program, as delineated in NUREG-1339, 

and industry recommendations, as delineated in 

EPRI NP-5769, with the exceptions noted in 

NUREG-1339 for safety-related bolting. The program 

also relies on industry recommendations for 

comprehensive bolting maintenance, as delineated in 

the EPRI TR-104213.

The program generally includes periodic inspection 

of closure bolting for indications of loss of preload, 

cracking, and loss of material due to corrosion, rust, 

etc. The program also includes preventive measures 

to preclude or minimize loss of preload and cracking.

Existing program

G

G

G

G
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A related aging management program (AMP) XI.M1,

“ASME Section XI Inservice Inspection (ISI) 

Subsections IWB, IWC, and IWD,” includes 

inspections of safety-related and non-safety-related 

closure bolting and supplements this bolting integrity 

program. Other related programs, AMPs XI.S1, 

“ASME Section XI, Subsection IWE”; XI.S3, “ASME 

Section XI Subsection IWF”; XI.S6, “Structures 

Monitoring”; XI.S7, “RG 1.127, “Inspection of WaterControl Structures Associated with Nuclear Power 

Plant”; and XI.M23, “Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling 

Systems,” manage the inspection of safety-related 

and non-safety related structural bolting.

XI.M19 Steam Generators

This program consists of aging management 

activities for the steam generator tubes, plugs, 

sleeves, and secondary side components that are 

contained within the steam generator in accordance 

with the plant technical specifications and includes 

commitments to NEI 97-06. 

Existing program G

XI.M20 Open-Cycle Cooling Water 

System 

This program relies on implementing NRC GL 89-13, 

which includes (a) surveillance and control of 

biofouling, (b) tests to verify heat transfer, (c) routine 

inspection and maintenance program, (d) system 

walkdown inspection, and (e) review of maintenance, 

operating, and training practices and procedures. 

The Open-Cycle Cooling Water System program 

applies to components constructed of various 

materials, including steel, stainless steel, aluminum 

copper alloys, polymeric materials, and concrete.

Existing program

G

G

G

G

XI.M21A Closed Treated Water 

Systems

The program includes (a) water treatment, including 

the use of corrosion inhibitors, to modify the chemical 

composition of the water such that the function of the 

Program should 

be implemented 

prior to period of 

G
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equipment is maintained and such that the effects of 

corrosion are minimized; (b) chemical testing of the 

water to ensure that the water treatment program 

maintains the water chemistry within acceptable 

guidelines; and (c) inspections to determine the 

presence or extent of corrosion and/or cracking.

extended 

operation

G

G

G

XI.M22 Boraflex Monitoring

The program consists of (a) neutron attenuation 

testing (“blackness testing”) to determine gap 

formation, (b) sampling for the presence of silica in 

the spent fuel pool along with boron loss, and (c) 

monitoring and analysis of criticality to assure that 

the required 5% sub-criticality margin is maintained. 

This program is implemented in response to NRC GL 

96-04.

Existing program G

XI.M23

Inspection of Overhead 

Heavy Load and Light 

Load Handling Related to 

Refueling) Handling 

Systems 

The program evaluates the effectiveness of the 

maintenance monitoring program and the effects of 

past and future usage on the structural reliability of 

cranes and hoists. The number and magnitude of lifts 

made by the hoist or crane are also reviewed. Rails 

and girders are visually inspected on a routine basis 

for degradation; functional tests are performed to 

assure their integrity. These cranes must also comply 

with the maintenance rule requirements provided in 

10 CFR 50.65. 

Existing program G

XI.M24 Compressed Air 

Monitoring 

The program consists of monitoring moisture content 

and corrosion, and performance of the entire system, 

including (a) preventive monitoring of water 

(moisture), and other contaminants to keep within the 

specified limits and (b) inspection of components for 

indications of loss of material due to corrosion. This 

program is in response to NRC GL 88-14 and INPO’s 

Significant Operating Experience Report (SOER) 88-

01. It also relies on the ASME OM Guide Part 17 and 

ISA-S7.0.1-1996 as guidance for testing and 

monitoring air quality and moisture.

Existing program G
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XI.M25 BWR Reactor Water 

Cleanup System

This program includes ISI and monitoring and control 

of reactor coolant water chemistry. Related to the 

inspection guidelines for RWCU piping welds 

outboard of the second isolation valve, the program 

includes measures delineated in NUREG-0313, 

Revision 2, and NRC GL 88-01 and ISI in 

conformance with the ASME Section XI.

Existing program G

XI.M26 Fire Protection

The program includes fire barrier inspections. The 

fire barrier inspection program requires periodic 

visual inspection of fire barrier penetration seals, fire 

barrier walls, ceilings, and floors, and periodic visual 

inspection and functional tests of fire-rated doors to 

ensure that their operability is maintained. The 

program also includes periodic inspection and testing

of halon/carbon dioxide fire suppression systems. 

Existing program G

XI.M27 Fire Water System

This program consists of periodic full-flow flush tests, 

system performance tests to prevent corrosion from 

biofouling components in the fire protection system,

and testing or replacement of sprinklers that have 

been in place for 50 years. The system is normally 

maintained at required operating pressure and is 

monitored such that loss of system pressure is 

immediately detected and corrective actions initiated. 

The program relies on the testing of piping and 

components in the water-based fire protection 

system in accordance with applicable National Fire 

Protection Association (NFPA) commitments. In 

addition, this program can be modified to include (a) 

portions of the fire protection sprinkler system that 

are subjected to full flow tests prior to the period of 

extended operation, and (b) portions of the fire 

protection system exposed to water are internally 

visually inspected.

Program should 

be implemented 

prior to period of 

extended 

operation

G

XI.M29 Aboveground Metallic 

Tanks

This program includes preventive measures to 

mitigate corrosion by protecting the external surfaces Existing program G

G
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of steel components, per standard industry practice, 

with sealant or caulking at the concrete-component

interface. Visual inspection during periodic system 

walkdowns should be sufficient to monitor 

degradation of the protective paint, coating, calking, 

or sealant. Program effectiveness is determined by 

measuring the thickness of the tank bottoms to 

ensure that significant degradation is not occurring 

and that the component’s intended function is 

maintained during the period of extended operation.

XI.M30 Fuel Oil Chemistry

The program relies on a combination of surveillance 

and maintenance procedures. Monitoring and 

controlling fuel oil contamination in accordance with 

the guidelines of American Society for Testing and 

Materials (ASTM) Standards D1796, D2276, D2709, 

and D4057 maintains the fuel oil quality. Exposure to 

fuel oil contaminants, such as water and 

microbiological organisms, is minimized by periodic 

cleaning/draining of tanks and by verifying the quality 

of new oil before its introduction into the storage 

tanks.

Existing program G

XI.M31 Reactor Vessel 

Surveillance

This program, extending the scope of 10 CFR Part 

50, Appendix H, “Reactor Vessel Material 

Surveillance Program Requirements,” provides 

sufficient material data and dosimetry to monitor 

irradiation embrittlement at the end of the period of 

extended operation, and to determine the need for 

operating restrictions on the inlet temperature, 

neutron spectrum, and neutron flux. If surveillance 

capsules are not withdrawn during the period of 

extended operation, operating restrictions are to be 

established to ensure that the plant is operated under 

the conditions to which the surveillance capsules 

were exposed. All capsules in the reactor vessel that 

are removed and tested must meet the test 

The surveillance 

capsule 

withdrawal 

schedule revised 

before the period 

of extended 

operation

G
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procedures and reporting requirements of ASTM E 

185-82 to the extent practicable for the configuration 

of the specimens in the capsule. Any changes to the 

capsule withdrawal schedule, including spare 

capsules, must be approved by the NRC prior to 

implementation. Untested capsules placed in storage 

must be maintained for future insertion. 

XI.M32 One-Time Inspection 

The program consists of a one-time inspection of 

selected components to verify the system-wide 

effectiveness of an AMP that is designed to prevent 

or minimize aging to the extent that it will not cause 

the loss of intended function during the period of 

extended operation. This program provides 

inspections that verify that unacceptable degradation 

is not occurring. It also may trigger additional actions 

that ensure the intended functions of affected 

components are maintained during the period of 

extended operation. 

The elements of the program include 

(a) determination of the sample size of components 

to be inspected based on an assessment of materials 

of fabrication, environment, plausible aging effects, 

and operating experience,(b) identification of the 

inspection locations in the system or component 

based on the potential for the aging effect to occur, 

(c) determination of the examination technique, 

including acceptance criteria that would be effective 

in managing the aging effect for which the 

component is examined, and (d) an evaluation of the 

need for follow-up examinations to monitor the 

progression of aging if age-related degradation is 

found that could jeopardize an intended function 

Program should 

be implemented 

prior to period of 

extended 

operation

G

G

G

G
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before the end of the period of extended operation. 

This program cannot be used for structures or 

components with known age-related degradation 

mechanisms or when the environment in the period 

of extended operation is not expected to be 

equivalent to that in the prior 40 years. Periodic 

inspections should be proposed in these cases.

XI.M33 Selective Leaching 

The program includes a one-time visual inspection 

coupled with either hardness measurement or other 

mechanical examination techniques such as 

destructive testing, scraping, or chipping of selected 

components that may be susceptible to selective 

leaching. This is to determine whether loss of 

materials is occurring and whether the process will 

affect the ability of the components to perform their 

intended function for the period of extended 

operation. 

Program should 

be implemented 

prior to period of 

extended 

operation

G

G

G

G

XI.M35

One-Time Inspection of 

ASME Code Class 1 Small 

Bore-Piping

This program augments the existing ASME Code, 

Section XI requirements and is applicable to smallbore ASME Code Class 1 piping and systems with a 

nominal pipe size diameter less than 4 inches 

(NPS<4) and greater than or equal to NPS 1. This 

program provides a one-time volumetric inspection of 

a sample of this Class 1 piping. The program 

includes pipes, fittings, branch connections, and all 

full and partial penetration (socket) welds. The 

program includes measures to verify that degradation 

is not occurring, thereby either confirming that there 

is no need to manage aging-related degradation or 

validating the effectiveness of any existing program 

for the period of extended operation. The one-time 

inspection program for ASME Code Class 1 smallbore piping includes locations that are susceptible to 

Program should 

be implemented 

prior to period of 

extended 

operation

G
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cracking. This program is applicable to systems that 

have not experienced cracking of ASME Code Class 

1 small-bore piping. This program can also be used 

for systems that experienced cracking but have 

implemented design changes to effectively mitigate 

cracking. (Measure of effectiveness includes (1) the 

one-time inspection sampling is statistically 

significant; (2) samples will be selected as described 

in Element 5; and (3) no repeated failures over an 

extended period of time.) For systems that have 

experienced cracking and operating experience 

indicates design changes have not been 

implemented to effectively mitigate cracking, periodic 

inspection is proposed, as managed by a plantspecific AMP. Should evidence of cracking be 

revealed by a one-time inspection, periodic 

inspection is also proposed, as managed by a plantspecific AMP.

XI.M36

External Surfaces 

Monitoring of Mechanical 

Components

This program is based on system inspections and 

walkdowns. This program consists of periodic visual 

inspections of metallic and polymeric components,

such as piping, piping components, ducting, 

polymeric components, and other components. The 

program manages aging effects through visual 

inspection of external surfaces for evidence of loss of 

material, cracking, and change in material properties. 

When appropriate for the component and material, 

manipulation may be used to augment visual 

inspection to confirm the absence of elastomer 

hardening and loss of strength.

Existing program

G

G

G

XI.M37 Flux Thimble Tube 

Inspection

The program inspects for the thinning of flux thimble 

tube walls, which provides a path for the in-core 

neutron flux monitoring system detectors and forms 

part of the reactor coolant system pressure 

boundary. Flux thimble tubes are subject to loss of 

Existing Program G
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material at certain locations in the reactor vessel 

where flow-induced fretting causes wear at 

discontinuities in the path from the reactor vessel 

instrument nozzle to the fuel assembly instrument 

guide tube. A nondestructive examination 

methodology, such as eddy current testing, or other 

applicant-justified and US NRC-accepted inspection 

methods are used to monitor flux thimble tube wear. 

This program implements the recommendations of 

NRC Bulletin 88-09, “Thimble Tube Thinning in 

Westinghouse Reactors.”

XI.M38

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

The program consists of inspections of the internal 

surfaces of metallic piping, piping components, 

ducting, polymeric components, and other 

components and any water systems other than opencycle cooling water, treated water, and fire water that 

are exposed to environments of air – indoor, 

uncontrolled; air – outdoor; condensation. These 

internal inspections are performed during the periodic 

system and component surveillances or during the 

performance of maintenance activities when the 

surfaces are made accessible for visual inspection. 

The program includes visual inspections to ensure 

that existing environmental conditions are not 

causing material degradation that could result in a 

loss of the component’s intended function. For 

certain materials, such as polymers, physical 

manipulation or pressurization (e.g., hydrotesting) to 

detect hardening or loss of strength is used to 

augment the visual examinations conducted under 

this program. If visual inspection of internal surfaces 

is not possible, then the applicant needs to provide a 

plant-specific program.

Existing program

G

G

G

G

XI.M39 Lubricating Oil Analysis This program ensures that the oil environment in the 

mechanical systems is maintained to the required Existing program G
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quality. The program ensures that oil systems are 

maintained free of contaminants (primarily water and 

particulates), thereby preserving an environment that 

is not conducive to loss of material or reduction of 

heat transfer. Testing activities include sampling and 

analysis of lubricating oil for detrimental 

contaminants. The presence of water or particulates 

may also indicate in-leakage and corrosion product 

buildup.

G

G

XI.M40

Monitoring of NeutronAbsorbing Materials other 

than Boraflex

This program relies on periodic inspection, testing, 

monitoring, and analysis of the criticality design to 

assure that the required 5 percent sub-criticality 

margin is maintained. 

Program should 

be implemented 

prior to period of 

extended 

operation

G

XI.M41 Buried and Underground 

Piping and Tanks

This comprehensive program is designed to manage 

the aging of the external surfaces of buried and 

underground piping and tanks. It addresses piping 

and tanks composed of any material, including 

metallic, polymeric, concrete, and cementitious 

materials. The program manages aging through 

preventive, mitigative, and inspection activities. It 

manages all applicable aging effects, such as loss of 

material, cracking, and changes in material 

properties.

Inspections to be 

completed before 

the period of 

extended 

operation

G

G

G

XI.S1

ASME Section XI, 

Subsection IWE Inservice 

Inspection (IWE)

The ASME Section XI, Subsection IWE program 

consists of periodic visual, surface, and volumetric 

inspection of pressure-retaining components of steel 

and concrete containments for signs of degradation, 

assessment of damage, and corrective actions. The 

program also includes aging management for the 

potential loss of material due to corrosion in the 

inaccessible areas of the BWR Mark I steel 

containment, and surface examination for the 

detection of cracking of structural bolting. This 

Existing program G
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program is in accordance with ASME Section XI, 

Subsection IWE, 2004 edition.

XI.S2

ASME Section XI, 

Subsection IWL Inservice 

Inspection (IWL)

The ASME Section XI, Subsection IWL program 

consists of (a) periodic visual inspection of concrete 

surfaces for reinforced and prestressed concrete 

containments, (b) periodic visual inspection and 

sample tendon testing of unbonded post-tensioning 

systems for prestressed concrete containments for 

signs of degradation, assessment of damage, and 

corrective actions, and testing of the tendon 

corrosion protection medium and free water. 

Measured tendon lift-off forces are compared to 

predicted tendon forces calculated in accordance 

with RG 1.35.1. This program is in accordance with 

ASME Section XI, Subsection IWL, 2004 edition. 

Existing program G

XI.S3

ASME Section XI, 

Subsection IWF Inservice 

inspection (IWF) 

This program consists of periodic visual examination 

of component supports and high-strength structural 

bolting for signs of degradation, evaluation, and 

corrective actions. This program is in accordance 

with ASME Section XI, Subsection IWF, 2004 edition. 

Existing program G

G

XI.S4 10 CFR Part 50, 

Appendix J

This program consists of monitoring leakage rates 

through containment liner/welds, penetrations, 

fittings, and other access openings to detect 

degradation of the containment pressure boundary. 

Corrective actions are taken if leakage rates exceed 

acceptance criteria. This program is implemented in 

accordance with 10 CFR Part 50 Appendix J, RG 

1.163 and NEI 94-01, Rev. 0.

Existing program G

XI.S5 Masonry Walls

The program consists of inspections, based on IE 

Bulletin 80-11 and plant-specific monitoring proposed 

by IN 87-67, for managing loss of material and 

cracking of masonry walls.

Existing program G

XI.S6 Structures Monitoring The program consists of periodic inspection and 

monitoring the condition of structures and structure Existing program G
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component supports to ensure that aging 

degradation leading to loss of intended functions will 

be detected and that the extent of degradation can 

be determined. This program is implemented in 

accordance with NUMARC 93-01, Rev. 2 and RG 

1.160, Rev. 2.

G

G

G

XI.S7

R.G. 1.127, Inspection of 

Water-Control Structures 

Associated with Nuclear 

Power Plants

The program consists of inspection and surveillance 

programs for dams, slopes, canals, intake structure,

and other water-control structures associated with 

emergency cooling water systems or flood protection 

based on RG 1.127, Rev. 1. The program also 

includes structural steel and structural bolting 

associated with water-control structures, steel or 

wood piles and sheeting required for the stability of 

embankments and channel slopes, and 

miscellaneous steel, such as sluice gates and trash 

racks.

Existing program G

XI.S8

Protective Coating 

Monitoring and 

Maintenance 

This program consists of guidance for selection, 

application, inspection, and maintenance of 

protective coatings. This program is implemented in 

accordance with RG 1.54, Rev. 1 or latest revision.

Existing program G

GALL 

Appendix A Quality Assurance

The 10 CFR Part 50, Appendix B quality assurance 

program provides for corrective actions, the 

confirmation process, and administrative controls for 

AMPs for license renewal. The scope of this existing 

program is expanded to include nonsafety-related 

structures and components that are subject to an 

AMR for license renewal.

Existing program

G

G

G

G

SRP 

Appendix A Plant-Specific AMP

The program should contain information associated 

with the bases for determining that aging effects will 

be managed during the period of extended operation.

Program should 

be implemented 

prior to period of 

extended 

operation

G

G

G
December 2010 3.0-25 NUREG-1800, Rev. 2

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems

GALL 

Chapter GALL Program Description of Program Implementation Schedule*

R

C

G

G

G

* An applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should verify that th

identified and committed in the license renewal application to any future aging management activities to be completed be

extended operation. The staff expects to impose a license condition on any renewed license to ensure that the applicant w

activities no later than the committed date.

December 2010 3.1-1 NUREG-1800, Rev. 2

3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR 

COOLANT SYSTEM

Review Responsibilities

Primary - Branch assigned responsibility by PM as described in SRP-LR Section 3.0 of this 

SRP-LR.

3.1.1 Areas of Review

This section addresses the aging management review (AMR) and the associated aging 

management program (AMP) 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 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, lowpressure 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. For PWRs the reactor coolant system also includes the 

pressurizer relief tank, which is not an 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 license renewal application (LRA) 

AMR and AMP items assigned to it, per SRP-LR Section 3.0:

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL Report AMPs 

• Plant-specific AMPs

FSAR Supplement

• The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP.
NUREG-1800, Rev. 2 3.1-2 December 2010

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 NRC’s regulations in 10 CFR 54.21.

3.1.2.1 AMR Results Consistent with the GALL Report 

The AMR and the AMPs applicable to the reactor vessel, internals, and reactor coolant system 

are described and evaluated in Chapter IV of NUREG-1801 (GALL Report).

The applicant’s LRA should provide sufficient information so that the reviewer is able to confirm 

that the specific LRA AMR item and the associated LRA AMP are consistent with the cited 

GALL Report AMR item. The reviewer should then confirm that the LRA AMR item is consistent 

with the GALL Report AMR item to which it is compared. When the applicant is crediting a 

different aging management program than recommended in the GALL Report, the reviewer 

should confirm that the alternate aging management program is valid to use for aging 

management and will be capable of managing the effects of aging as adequately as the aging 

management program recommended by the GALL Report.

3.1.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 the GALL Report AMR item to 

which the LRA AMR item is compared identifies that further evaluation is recommended, then 

additional criteria apply as identified by the GALL Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.1-1, comparing the “Further Evaluation 

Recommended” and the “Rev2 Item” columns, for the AMR items that reference the following 

subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.1.2.2.1 Cumulative Fatigue Damage

Fatigue 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). This TLAA is addressed separately in 

Section 4.3, “Metal Fatigue Analysis,” of this SRP-LR. 

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 steam generator 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 steam generator 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, the program may not be sufficient to 

detect pitting and crevice corrosion, if general and pitting corrosion of the shell is known 

to exist. The GALL Report recommends augmented inspection to manage this aging 

effect. Furthermore, the GALL Report clarifies that 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 

RLSB-1 (Appendix A.1 of this SRP-LR). 
December 2010 3.1-3 NUREG-1800, Rev. 2

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 

steam generators, generating a cut in the middle of the transition cone, and,

consequently, a new transition cone closure weld. The GALL Report recommends

volumetric examinations performed in accordance with the requirements of ASME Code 

Section XI for upper shell-to 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 Steam Generators, 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 Section XI 

requirements. In addition, ASME Section XI does not require licensees to remove 

insulation when performing visual examination on non-borated 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, the GALL Report recommends further 

evaluation 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 period of extended 

operation. Furthermore, the GALL Report clarifies that this issue is limited to 

replacement recirculating steam generators with a new transition cone closure weld.

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 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 license renewal term. 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 Vessel Neutron Embrittlement Analysis,” of this SRP-LR.

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 materials surveillance program monitors neutron 

irradiation embrittlement of the reactor vessel. The reactor vessel surveillance program 

is plant-specific, depending on matters such as the composition of limiting materials, 

availability of surveillance capsules, and projected fluence levels. In accordance with 
NUREG-1800, Rev. 2 3.1-4 December 2010

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 staff evaluation is required for license 

renewal. Specific recommendations for an acceptable AMP are provided in Chapter XI, 

Section M31 of the GALL Report. 

3. Ductility – Reduction in Fracture Toughness is a plant-specific TLAA for Babcock and 

Wilcox (B&W) reactor internals to be evaluated for the period of extended operation in 

accordance with the staff’s safety evaluation concerning “Demonstration of the 

Management of Aging Effects for the Reactor Vessel Internals,” Babcock and Wilcox 

Owners Group report number BAW-2248, which is included in BAW-2248A, March 2000.

Plant-specific TLAAs are addressed in Section 4.7, “Other Plant-Specific Time-Limited 

Aging Analyses,” of this SRP-LR.

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 the stainless steel and nickel alloy BWR top head 

enclosure vessel flange leak detection lines. The GALL Report recommends that a plantspecific AMP be evaluated because existing programs may not be capable of mitigating 

or detecting cracking due to SCC and IGSCC. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

2. Cracking due to SCC and IGSCC could occur in stainless steel BWR isolation 

condenser components exposed to reactor coolant. The existing program relies on 

control of reactor water chemistry to mitigate SCC and on ASME Section XI ISI to detect 

cracking. However, the existing program should be augmented to detect cracking due to 

SCC and IGSCC. The GALL Report recommends an augmented program 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 

period of extended operation. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR). 

3.1.2.2.5 Crack Growth due to Cyclic Loading

Crack growth due to cyclic loading could occur in reactor vessel shell forgings clad with 

stainless steel using a high-heat-input welding process. Growth of intergranular separations

(underclad cracks) in the heat-affected zone under austenitic stainless steel cladding is a TLAA 

to be evaluated for the period of extended operation for all the SA-508-Cl-2 forgings where the 

cladding was deposited with a high heat input welding process. The methodology for evaluating 

the underclad flaw should be consistent with the flaw evaluation procedure and criterion in the 

ASME Section XI Code, 2004 edition1

 1 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.

. See the SRP-LR, Section 4.7, “Other Plant-Specific 

Time-Limited Aging Analysis,” for generic guidance for meeting the requirements of 10 CFR 

54.21(c). 
December 2010 3.1-5 NUREG-1800, Rev. 2

3.1.2.2.6 Cracking due to Stress Corrosion Cracking

1. Cracking due to SCC could occur in the PWR stainless steel reactor vessel flange leak 

detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant. 

The GALL Report recommends further evaluation to ensure that these aging effects are 

adequately managed. The GALL Report recommends that a plant-specific AMP be 

evaluated to ensure that this aging effect is adequately managed. Acceptance criteria 

are described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR). 

2. Cracking due to SCC could occur in Class 1 PWR cast austenitic stainless steel (CASS) 

reactor coolant system piping, piping components, and piping elements exposed to 

reactor coolant. The existing program relies on control of water chemistry to mitigate 

SCC; however, SCC could occur for CASS components that do not meet the NUREG0313 guidelines with regard to ferrite and carbon content. The GALL Report 

recommends further evaluation of a plant-specific program for these components to 

ensure that this aging effect is adequately managed. Acceptance criteria are described 

in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR). 

3.1.2.2.7 Cracking due to Cyclic Loading

Cracking due to cyclic loading could occur in steel and stainless steel BWR isolation condenser 

components exposed to reactor coolant. The existing program relies on ASME Section XI ISI. 

However, the existing program should be augmented to detect cracking due to cyclic loading. 

The GALL Report recommends an augmented program 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 period of extended operation. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

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. The GALL Report recommends further 

evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR). 

3.1.2.2.9 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking 

Cracking due to SCC and irradiation-assisted stress corrosion cracking (IASCC) could occur in 

inaccessible locations for stainless steel and nickel-alloy Primary and Expansion PWR reactor 

vessel internal components. If aging effects are identified in accessible locations, the GALL 

Report recommends further evaluation of the aging effects in inaccessible locations on a plantspecific basis to ensure that this aging effect is adequately managed. Acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).
NUREG-1800, Rev. 2 3.1-6 December 2010

3.1.2.2.10 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement, 

Change in Dimension due to Void Swelling, Loss of Preload due to Stress 

Relaxation, or Loss of Material due to Wear

Loss of fracture toughness due to neutron irradiation embrittlement, change in dimension due to 

void swelling, loss of preload due to stress relaxation, or loss of material due to wear could 

occur in inaccessible locations for stainless steel and nickel-alloy Primary and Expansion PWR 

reactor vessel internal components. If aging effects are identified in accessible locations, the 

GALL Report recommends further evaluation of the aging effects in inaccessible locations on a 

plant-specific basis to ensure that this aging effect is adequately managed. Acceptance criteria 

are described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

3.1.2.2.11 Cracking due to Primary Water Stress Corrosion Cracking 

1. Foreign operating experience in steam generators with a similar design to that of 

Westinghouse Model 51 has identified extensive cracking 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 (EPRI TR-1014982). Cracks have been detected in the stub 

runner, adjacent to the tubesheet/stub runner weld and with depths of almost a third of 

the divider plate thickness. Therefore, the water chemistry program may not be effective 

in managing the aging effect of cracking due to PWSCC in SG divider plate assemblies. 

This is of particular concern for steam generators where the tube-tubesheet welds are 

considered structural welds and/or where the divider plate assembly contributes to the 

mechanical integrity of the tubesheet.

Although these SG divider plate cracks may not have a significant safety impact in and

of themselves, these cracks could impact adjacent items, such as the tubesheet and the 

channel head, if they propagate to the boundary with these items. For the tubesheet, 

PWSCC cracks in the divider plate could propagate to the tubesheet cladding with 

possible consequences to the integrity of the tube/tubesheet welds. For the channel 

head, the PWSCC cracks in the divider plate could propagate to the SG triple point and 

potentially affect the pressure boundary of the SG channel head.

The existing program relies on control of reactor water chemistry to mitigate cracking 

due to PWSCC. The GALL Report recommends that a plant-specific AMP be evaluated, 

along with the primary water chemistry program, because the existing primary water 

chemistry program may not be capable of mitigating cracking due to PWSCC. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of 

this SRP-LR).

2. Cracking due to PWSCC could occur in steam generator nickel alloy tube-to-tubesheet 

welds exposed to reactor coolant. Unless the NRC has approved a redefinition of the 

pressure boundary in which the tube-to-tubesheet weld is no longer included, the 

effectiveness of the primary water chemistry program should be verified to ensure 

cracking is not occurring:

• For plants with Alloy 600 steam generator tubes that have not been thermally 

treated and for which an alternate repair criteria such as C*, F* or W* has been 

permanently approved, the weld is no longer part of the pressure boundary and 

no plant specific aging management program is required; 
December 2010 3.1-7 NUREG-1800, Rev. 2

• For plants with Alloy 600 steam generator tubes that have not been thermally 

treated and for which there is no permanently approved alternate repair criteria 

such as C*, F* or W*, a plant-specific AMP is required;

• For plants with Alloy 600TT steam generator tubes and for which an alternate 

repair criteria such as H* has been permanently approved, the weld is no longer 

part of the pressure boundary and no plant specific aging management program 

is required;

• For plants with Alloy 600TT steam generator tubes and for which there is no 

alternate repair criteria such as H* permanently approved, a plant-specific AMP 

is required;

• For plants with Alloy 690TT steam generator tubes with Alloy 690 tubesheet 

cladding, the water chemistry is sufficient, and no further action or plant-specific 

aging management program is required;

• For plants with Alloy 690TT steam generator tubes and with Alloy 600 tubesheet 

cladding, either a plant-specific program or a rationale for why such a program is 

not needed is required.

The existing program relies on control of reactor water chemistry to mitigate cracking 

due to PWSCC. The GALL Report recommends that a plant-specific AMP be evaluated, 

along with the primary water chemistry program, because the existing primary water 

chemistry program may not be capable of mitigating cracking due to PWSCC. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of 

this SRP-LR).

3.1.2.2.12 Cracking due to Fatigue

EPRI 1016596, Materials Reliability Program: Pressurized Water Reactor Internals Inspection 

and Evaluation Guidelines (MRP-227-Rev. 0) identifies cracking due to fatigue as an aging 

effect that can occur for the lower flange weld in the core support barrel assembly, fuel 

alignment plate in the upper internals assembly, and core support plate lower support structure

in PWR internals designed by Combustion Engineering. The GALL Report recommends that 

inspection for cracking in this component be performed if acceptable fatigue life cannot be 

demonstrated by TLAA through the period of extended operation as defined in 10 CFR 54.3.

3.1.2.2.13 Cracking due to Stress Corrosion Cracking and Fatigue

Cracking due to stress corrosion cracking and fatigue could occur in nickel alloy control rod 

guide tube assemblies, guide tube support pins exposed to reactor coolant, and neutron flux. 

The GALL Report, AMR Item IV.B2.RP-355, recommends further evaluation of a plant-specific 

AMP to ensure this aging effect is adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

3.1.2.2.14 Loss of Material due to Wear

Loss of material due to wear could occur in nickel alloy control rod guide tube assemblies, guide 

tube support pins and in Zircaloy-4 incore instrumentation lower thimble tubes exposed to 

reactor coolant, and neutron flux. The GALL Report, AMR Items IV.B2.RP-356 and IV.B3.RP357, recommends further evaluation of a plant-specific AMP to ensure this aging effect is 

adequately managed. Acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR).
NUREG-1800, Rev. 2 3.1-8 December 2010

3.1.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2 of this 

SRP-LR).

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

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 Report, the NRC reviewer performs an audit of aging 

management programs credited in the LRA to confirm consistency with the GALL AMPs 

identified in the GALL Report, Chapters X and XI.

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP with all 

exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, the 

reviewer identifies a difference between the LRA AMP and the GALL Report AMP that should 

have been identified as an exception to the GALL Report AMP, the difference should be 

reviewed and properly dispositioned. The reviewer should document the disposition of all LRAdefined exceptions and staff-identified differences. 

The LRA should identify any enhancements that are needed to permit an existing licensee AMP 

to be declared consistent with the GALL 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 Report AMP and that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the 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 AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.1.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

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 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 3.0-1 of this SRP-LR provides 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-LR subsection. 
December 2010 3.1-9 NUREG-1800, Rev. 2

3.1.3 Review Procedures

For each area of review, the following review procedures are to be followed.

3.1.3.1 AMR Results Consistent with the GALL Report

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to the GALL Report in its LRA. 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 applicant 

has stated that the applicable aging effects and industry and plant-specific operating experience 

have been reviewed by the applicant and are evaluated in the GALL Report. 

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL 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 

Report as applicable to its plant. 

3.1.3.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to which the 

LRA AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL Report for each of the following aging effect/aging 

mechanism combinations. 

3.1.3.2.1 Cumulative Fatigue Damage 

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c)(1). The staff reviews the evaluation of this TLAA separately 

following the guidance in Section 4.3 of this SRP-LR. 

3.1.3.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion 

1. The GALL Report recommends an augmented program for the management of loss of 

material due to general, pitting, and crevice corrosion for steel PWR steam generator 

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 steam generator 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, the GALL Report recommends augmented inspection to manage this aging 

effect. Furthermore, the GALL Report clarifies that this issue is limited to Westinghouse 

Model 44 and 51 Steam Generators where a high-stress region exists at the shell to 
NUREG-1800, Rev. 2 3.1-10 December 2010

transition cone weld. Acceptance criteria are described in Branch Technical Position 

RLSB-1 (Appendix A.1 of this SRP-LR). 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 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 period of 

extended operation. 

2. The GALL Report recommends further evaluation 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 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 aging management program 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 period of extended operation for the new transition cone 

closure weld.

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 staff reviews the 

evaluation of this TLAA following the guidance in Section 4.2 of this SRP-LR.

2. The GALL Report recommends further evaluation of the reactor vessel materials 

surveillance program for the period of extended operation. Neutron embrittlement of the 

reactor vessel is monitored by a reactor vessel materials surveillance program. Reactor 

vessel surveillance program is plant-specific, depending on matters such as the 

composition of limiting materials, availability of surveillance capsules, and projected 

fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant must 

submit its proposed withdrawal schedule for approval prior to implementation. Untested 

capsules placed in storage must be maintained for future insertion. Thus, further staff 

evaluation is required for license renewal. The reviewer verifies on a case-by-case basis 
December 2010 3.1-11 NUREG-1800, Rev. 2

that the applicant has proposed an adequate reactor vessel materials surveillance 

program for the period of extended operation. Specific recommendations for an 

acceptable AMP are provided in Chapter XI, Section M31 of the GALL Report. 

3. Ductility – Reduction in Fracture Toughness for Babcock and Wilcox 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 staff reviews the evaluation of this TLAA following the 

guidance in Section 4.7 of this SRP-LR consistent with the action item documented in 

the staff’s safety evaluation for MRP-227, Revision 0.

3.1.3.2.4 Cracking due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking

1. The GALL Report recommends that a plant-specific AMP be evaluated to manage 

cracking due to SCC and IGSCC in stainless steel and nickel alloy BWR top head 

enclosure vessel flange leak detection lines. 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. The GALL Report recommends an augmented program 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 stainless steel BWR isolation 

condenser components. The existing program relies on control of reactor water 

chemistry to mitigate SCC and IGSCC and on ASME 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 

The GALL Report recommends further evaluation of programs to manage crack growth due to 

cyclic loading in reactor vessel shell forgings clad with stainless steel using a high-heat-input 

welding process. Growth of intergranular separations (underclad cracks) in the heat affected 

zone under austenitic stainless steel cladding is a TLAA to be evaluated for the period of 

extended operation for all the SA-508-Cl-2 forgings where the cladding was deposited with a 

high heat input welding process. The methodology for evaluating the underclad flaw should be 

consistent with the current well-established flaw evaluation procedure and criterion in the ASME 

Section XI Code. The SRP-LR, Section 4.7, “Other Plant-Specific Time-Limited Aging Analysis,” 

provides generic guidance for meeting the requirements of 10 CFR 54.21(c). The staff reviews 

the evaluation of this TLAA separately following the guidance in Section 4.7 of this SRP-LR.

3.1.3.2.6 Cracking due to Stress Corrosion Cracking

1. The GALL Report recommends that a plant-specific AMP be evaluated to manage 

cracking due to SCC in stainless steel PWR reactor vessel flange leak detection lines 

and 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.
NUREG-1800, Rev. 2 3.1-12 December 2010

2. The GALL Report recommends that a plant-specific AMP be evaluated to manage 

cracking due to SCC in CASS PWR Class 1 reactor coolant system piping, piping 

components, and piping elements 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. 

3.1.3.2.7 Cracking due to Cyclic Loading

The GALL Report recommends an augmented program for the management of cracking due to 

cyclic loading in steel and stainless steel BWR isolation condenser components. The existing 

program relies on ASME 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 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 period of extended operation.

3.1.3.2.8 Loss of Material due to Erosion 

The GALL Report recommends further evaluation of a plant-specific AMP 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 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking

The GALL Report recommends further evaluation of cracking due to SCC and IASCC for 

inaccessible locations for Primary and Expansion PWR reactor vessel internal components if 

aging effects are identified for these components in accessible locations. 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 consistent with the action item 

documented in the staff’s safety evaluation for MRP-227, Revision 0..

3.1.3.2.10 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement; 

Change in Dimension due to Void Swelling; Loss of Preload due to Stress 

Relaxation; or Loss of Material due to Wear

The GALL Report recommends further evaluation of loss of fracture toughness due to neutron 

irradiation embrittlement, change in dimension due to void swelling, loss of preload due to stress 

relaxation, or loss of material due to wear for inaccessible locations for Primary and Expansion 

PWR reactor vessel internal components, if aging effects are identified for these components in 

accessible locations. 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 consistent with the action item documented in the staff’s safety evaluation for MRP-227, 

Revision 0.
December 2010 3.1-13 NUREG-1800, Rev. 2

3.1.3.2.11 Cracking due to Primary Water Stress Corrosion Cracking

1. The GALL Report recommends that a plant-specific AMP be evaluated, along with the 

primary water chemistry program, to manage cracking due to PWSCC in nickel alloy 

divider plate assemblies made of Alloy 600 and/or the associated Alloy 600 weld 

materials for steam generators with a similar design to that of Westinghouse Model 51. 

The effectiveness of the chemistry control program should be verified to ensure that 

cracking due to PWSCC is not occurring. The reviewer verifies the materials of 

construction of the applicant's SG divider plate assembly. If these materials are 

susceptible to cracking, the reviewer verifies that the applicant has evaluated the 

potential for cracking in the divider plate to propagate into other components (e.g., 

tubesheet cladding). If propagation into these other components is possible, the reviewer 

verifies if the applicant has described an inspection program (examination technique and 

frequency) for ensuring that no cracks are propagating into other items (e.g., tube sheet 

and channel head) that could challenge the integrity of those items. 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 this aging effect.

2. The GALL Report recommends that a plant-specific AMP be evaluated, along with the 

primary water chemistry program, to manage cracking due to PWSCC in recirculating 

steam generator nickel alloy tube-to-tubesheet welds exposed to reactor coolant. The 

effectiveness of the primary water chemistry program should be verified to ensure that 

cracking due to PWSCC is not occurring. 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. If this combination requires further 

evaluation, 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 this 

aging effect.

3.1.3.2.12 Cracking due to Fatigue

The GALL Report recommends further evaluation of cracking due to fatigue in the lower flange 

weld in the core support barrel assembly, fuel alignment plate in the upper internals assembly, 

and core support plate in the lower support structure in PWR internals designed by Combustion 

Engineering. The reviewer determines whether a TLAA has been performed for each 

component, consistent with the action item documented in the staff’s safety evaluation for MRP227, Revision 0. If a TLAA has not been performed, the reviewer determines whether the 

applicant has performed an evaluation to identify the potential location and extent of fatigue 

cracking for each component consistent with the action item documented in the staff’s safety 

evaluation for MRP-227, Revision 0.

3.1.3.2.13 Cracking due to Stress Corrosion Cracking and Fatigue

The GALL Report recommends further evaluation of cracking due to stress corrosion cracking 

and fatigue in the nickel alloy control rod guide tube assemblies, guide tube support pins 

exposed to reactor coolant, and neutron flux. 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 consistent with the action item documented in the staff’s 

safety evaluation for MRP-227, Revision 0.

.
NUREG-1800, Rev. 2 3.1-14 December 2010

3.1.3.2.14 Loss of Material due to Wear

The GALL Report recommends further evaluation of loss of material due to wear in nickel alloy 

control rod guide tube assemblies, guide tube support pins and in Zircaloy-4 incore 

instrumentation lower thimble tubes exposed to reactor coolant, and neutron flux. 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 consistent with the action 

item documented in the staff’s safety evaluation for MRP-227, Revision 0.

3.1.3.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

The applicant’s AMPs for license renewal 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 aging 

management review for license renewal. 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.

3.1.3.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

The reviewer should confirm that the applicant, in its LRA, 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 Report or a plant-specific program. Review procedures 

are described in Branch Technical Position RSLB-1 (Appendix A.1 of this SRP-LR).

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA 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 LRA, between the LRA AMP and the GALL Report AMP, with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA 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 Report pertinent to the reactor vessel, 

internals, and reactor coolant system are summarized in Table 3.1-1 of this SRP-LR. The “Rev 

2 Item” (for 2010) and “Rev1 Item” (for 2005 counterpart) columns identify the AMR item 

numbers in the GALL Report, Chapter IV, presenting detailed information summarized by this 

row.
December 2010 3.1-15 NUREG-1800, Rev. 2

3.1.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in its FSAR supplement information 

equivalent to that in Table 3.0-1 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-LR 

subsection. The reviewer also confirms that the applicant has provided information for 

Subsection 3.1.3.3, “AMR Results Not Consistent with or Not Addressed in the GALL Report,” 

equivalent to that in Table 3.0-1.

The 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 conditions 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 and finds it acceptable 

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.

As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before entering the period of extended

operation. The 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 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 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 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 reactor vessel, internals and reactor coolant system, as required by 

10 CFR 54.21(d).

3.1.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.

3.1.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.
NUREG-1800, Rev. 2 3.1-16 December 2010

2. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

3. NEI 97-06, “Steam Generator Program Guidelines,” Revision 2, Nuclear Energy Institute, 

September 2005.

4. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.

5. NRC Information Notice 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth Welds 

in Steam Generators,” U.S. Nuclear Regulatory Commission, January 26, 1990.

6. NUREG-0313, Rev. 2, “Technical Report on Material Selection and Processing Guidelines 

for BWR Coolant Pressure Boundary Piping,” U.S. Nuclear Regulatory Commission, 

January 1988.

7. EPRI 1013706, “PWR Steam Generator Examination Guidelines, Rev. 7,” Electric Power 

Research Institute, October 2007.

8. NRC Regulatory Guide 1.121, “Bases for Plugging Degraded PWR Steam Generator Tubes 

(for Comment),” U.S. Nuclear Regulatory Commission, May 1976. 

9. NRC Generic Letter 95-05, “Voltage-Based Repair Criteria for Westinghouse Steam 

Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking,” U.S. Nuclear 

Regulatory Commission, August 3, 1995.

10. NRC Information Notice 90-10, “Primary Water Stress Corrosion Cracking (PWSCC) of 

Inconel 600,” U.S. Nuclear Regulatory Commission, February 23, 1990.

11. NRC Information Notice 90-30, “Ultrasonic Inspection Techniques for Dissimilar Metal 

Welds,” U.S. Nuclear Regulatory Commission, May 1, 1990.

12. NRC Generic Letter 89-08, “Erosion/Corrosion-Induced Pipe Wall Thinning,” May 2, 1989.

13. NSAC-202L-R3, “Recommendations for an Effective Flow-accelerated Corrosion Program,” 

Electric Power Research Institute, April 1999.

14. NRC Information Notice 96-11, “Ingress of Demineralizer Resins Increase Potential for 

Stress Corrosion Cracking of Control Rod Drive Mechanism Penetrations,” February 14, 

1996.

15. BWRVIP-190 (EPRI 1016579), BWR Vessel and Internals Project: BWR Water Chemistry 

Guidelines-2008 Revision, Electric Power Research Institute, Palo Alto, CA, October 2008

16. EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 

and 2, Electric Power Research Institute, Palo Alto, CA, April 1988.

17. EPRI 1014986, “PWR Primary Water Chemistry Guidelines,” Revision 6, Volumes 1 and 2, 

Electric Power Research Institute, Palo Alto, CA, December 2007.

18. NRC Generic Letter 88-01, “NRC Position on IGSCC in BWR Austenitic Stainless Steel 

Piping,” January 25, 1988.
December 2010 3.1-17 NUREG-1800, Rev. 2

19. NRC Generic Letter 97-01, “Degradation of Control Rod Drive Mechanism Nozzle and Other 

Vessel Closure Head Penetrations,” April 1, 1997.

20. NRC Information Notice 97-46, “Unisolable Crack in High-Pressure Injection Piping,” July 9, 

1997.

21. NRC Regulatory Guide 1.99, Rev. 2, “Radiation Embrittlement of Reactor Vessel Materials,”

May 1988.

22. NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle 

Cracking,” U.S. Nuclear Regulatory Commission, November 1980.

23. NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in 

Nuclear Power Plants,” Richard E. Johnson, U.S. Nuclear Regulatory Commission, June 

1990.

24. EPRI TR-104213, “Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute,” Palo Alto, CA, December 1995.

25. NEI letter dated Dec. 11, 1998, Dave Modeen to Gus Lainas, “Responses to NRC Requests 

for Additional Information (RAIs) on GL 97-01.”

26. EPRI 1016555, “PWR Secondary Water Chemistry Guidelines–Revision 7,” Electric Power 

Research Institute, Palo Alto, CA, February 2009.

27. NRC Information Notice 91-19, “Steam Generator Feedwater Distribution Piping Damage,”

March 12, 1991.

28. EPRI 1016596, “Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guidelines,” MRP-227, Revision 0, Electric Power Research 

Institute, Palo Alto, CA, December 2008.

29. Topical Report, “Demonstration of the Management of Aging Effects for the Reactor Vessel 

Internals,” BAW-2248A, March 2000.

30. 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,” Electric Power Research Institute, Palo 

Alto, CA, June 2007.
NUREG-1800, Rev. 2 3.1-18 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

1 BWR/

PWR

High strength, low-alloy 

steel top head closure 

stud assembly exposed 

to air with potential for 

reactor coolant leakage

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation (See 

SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

2 PWR Nickel alloy tubes and 

sleeves exposed to 

reactor coolant and 

secondary 

feedwater/steam

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation (See 

SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

3 BWR/

PWR

Stainless steel or nickel 

alloy reactor vessel 

internal components 

exposed to reactor 

coolant and neutron flux

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation (See 

SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

4 BWR/

PWR

Steel pressure vessel 

support skirt and 

attachment welds

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation (See 

SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)
December 2010 3.1-19 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

5 PWR Steel, stainless steel, or 

steel (with stainless steel 

or nickel alloy cladding) 

steam generator 

components, pressurizer 

relief tank components 

or piping components or 

bolting

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation (See 

SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

6 BWR Steel (with or without 

nickel-alloy or stainless 

steel cladding), or 

stainless steel; or nickel 

alloy reactor coolant 

pressure boundary 

components: piping, 

piping components, and 

piping elements exposed 

to reactor coolant

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation, and for 

Class 1 components 

environmental effects on 

fatigue are to be addressed. 

(See SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

7 BWR Steel (with or without 

nickel-alloy or stainless 

steel cladding), or 

stainless steel; or nickel 

alloy reactor vessel 

components: flanges; 

nozzles; penetrations; 

safe ends; thermal 

sleeves;vessel shells, 

heads and welds 

exposed to reactor 

coolant

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation, and for 

Class 1 components 

environmental effects on 

fatigue are to be addressed. 

(See SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)
NUREG-1800, Rev. 2 3.1-20 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

8 PWR Steel (with or without 

nickel-alloy or stainless 

steel cladding), or 

stainless steel; or nickel 

alloy steam generator 

components exposed to 

reactor coolant

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation, and for 

Class 1 components 

environmental effects on 

fatigue are to be addressed. 

(See SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

9 PWR Steel (with or without 

nickel-alloy or stainless 

steel cladding), stainless 

steel; nickel alloy RCPB 

piping; flanges; nozzles 

& safe ends; pressurizer 

shell heads & welds; 

heater sheaths & 

sleeves; penetrations; 

thermal sleeves exposed 

to reactor coolant

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation, and for 

Class 1 components 

environmental effects on 

fatigue are to be addressed. 

(See SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

10 PWR Steel (with or without 

nickel-alloy or stainless 

steel cladding), stainless 

steel; nickel alloy reactor 

vessel flanges; nozzles; 

penetrations; pressure 

housings; safe ends; 

thermal sleeves; vessel 

shells, heads and welds 

exposed to reactor 

coolant

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation, and for 

Class 1 components 

environmental effects on 

fatigue are to be addressed. 

(See SRP, Sec 4.3 “Metal 

Fatigue,” for acceptable 

methods to comply with 10 

CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)
December 2010 3.1-21 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

11 BWR Steel or stainless steel 

pump and valve closure 

bolting exposed to high 

temperatures and 

thermal cycles

Cumulative fatigue 

damage due to fatigue

Fatigue is a TLAA 

evaluated for the period of 

extended operation; check 

ASME Code limits for 

allowable cycles (less than 

7000 cycles) of thermal 

stress range. (SRP Sec 4.3 

“Metal Fatigue,” for 

acceptable methods to 

comply with 10 CFR 

54.21(c)(1))

Yes, TLAA (See 

subsection 3.1.2.2.1)

12 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, and 

crevice corrosion

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water 

Chemistry," and, for 

Westinghouse Model 44 

and 51 S/G, if corrosion of 

the shell is found, additional 

inspection procedures are 

developed

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.1.2.2.2.1 and 

3.1.2.2.2.2)

13 BWR/

PWR

Steel (with or without 

stainless steel cladding) 

reactor vessel beltline 

shell, nozzles, and welds 

exposed to reactor 

coolant and neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement

TLAA is to be evaluated in 

accordance with Appendix 

G of 10 CFR Part 50 and 

RG 1.99. The applicant may 

choose to demonstrate that 

the materials of the nozzles 

are not controlling for the 

TLAA evaluations

Yes, TLAA (See 

subsection 

3.1.2.2.3.1)
NUREG-1800, Rev. 2 3.1-22 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

14 BWR/

PWR

Steel (with or without 

cladding) reactor vessel 

beltline shell, nozzles, 

and welds; safety 

injection nozzles

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement

Chapter XI.M31, “Reactor 

Vessel Surveillance”

Yes, plant specific or 

integrated 

surveillance program 

(See subsection 

3.1.2.2.3.2)

15 PWR Stainless steel and 

nickel alloy reactor 

vessel internal 

components exposed to 

reactor coolant and 

neutron flux

Reduction in ductility and 

fracture toughness due 

to neutron irradiation

Ductility - Reduction in 

Fracture Toughness is a 

TLAA to be evaluated for 

the period of extended 

operation. See the SRP, 

Section 4.7, "Other PlantSpecific TLAAs," for 

acceptable methods for 

meeting the requirements of 

10 CFR 54.21(c)(1).

Yes, TLAA (See 

subsection 

3.1.2.2.3.3)

16 BWR Stainless steel and 

nickel alloy top head 

enclosure vessel flange 

leak detection line

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

A plant-specific aging 

management program is to 

be evaluated because 

existing programs may not 

be capable of mitigating or 

detecting crack initiation 

and growth due to SCC in 

the vessel flange leak 

detection line

Yes, plant-specific 

(See subsection 

3.1.2.2.4.1)

17 BWR Stainless steel isolation 

condenser components 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry” for BWR water, 

and a plant-specific 

verification program

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.1.2.2.4.2)
December 2010 3.1-23 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

18 PWR Reactor vessel shell 

fabricated of SA508-Cl 2 

forgings clad with 

stainless steel using a 

high-heat-input welding 

process exposed to 

reactor coolant

Crack growth due to 

cyclic loading

Growth of intergranular 

separations is a TLAA 

evaluated for the period of 

extended operation. The 

Standard Review Plan, 

Section 4.7, “Other PlantSpecific Time-Limited Aging 

Analysis,” provides 

guidance for meeting the 

requirements of 10 CFR 

54.21(c).

Yes, TLAA (See 

subsection 3.1.2.2.5)

19 PWR Stainless steel reactor 

vessel closure head 

flange leak detection line 

and bottom-mounted 

instrument guide tubes 

(external to reactor 

vessel)

Cracking due to stress 

corrosion cracking

A plant-specific aging 

management program is to 

be evaluated

Yes, plant-specific 

(See subsection 

3.1.2.2.6.1)

20 PWR Cast austenitic stainless 

steel Class 1 piping, 

piping components, and 

piping elements exposed 

to reactor coolant

Cracking due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry” and, for CASS 

components that do not 

meet the NUREG-0313 

guidelines, a plant specific 

aging management 

program

Yes, plant-specific 

(See subsection 

3.1.2.2.6.2)

21 BWR Steel and stainless steel 

isolation condenser 

components exposed to 

reactor coolant

Cracking due to cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components The 

ISI program is to be 

augmented by a plantspecific verification program

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 3.1.2.2.7)
NUREG-1800, Rev. 2 3.1-24 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

22 PWR Steel steam generator 

feedwater impingement 

plate and support 

exposed to secondary 

feedwater

Loss of material due to 

erosion

A plant-specific aging 

management program is to 

be evaluated

Yes, plant-specific 

(See subsection 

3.1.2.2.8)

23 PWR Stainless steel or nickel 

alloy PWR reactor 

vessel internal 

components 

(inaccessible locations) 

exposed to reactor 

coolant and neutron flux

Cracking due to stress 

corrosion cracking, and 

irradiation-assisted 

stress corrosion cracking

Chapter XI.M16A, “PWR 

Vessel Internals," and 

Chapter XI.M2, “Water 

Chemistry”

Yes, if accessible 

Primary, Expansion 

or Existing program 

components indicate 

aging effects that 

need management 

(See subsection 

3.1.2.2.9)

24 PWR Stainless steel or nickel 

alloy PWR reactor 

vessel internal 

components 

(inaccessible locations) 

exposed to reactor 

coolant and neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement; or 

changes in dimension 

due to void swelling; or 

loss of preload due to 

thermal and irradiation 

enhanced stress 

relaxation; or loss of 

material due to wear

Chapter XI.M16A, “PWR 

Vessel Internals”

Yes, if accessible 

Primary, Expansion 

or Existing program 

components indicate 

aging effects that 

need management 

(See subsection 

3.1.2.2.10)

25 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 stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry”

Yes, plant-specific 

(See subsections 

3.1.2.2.11.1 and 

3.1.2.2.11.2)
December 2010 3.1-25 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

26 PWR Stainless steel 

Combustion Engineering 

core support barrel 

assembly: lower flange 

weld exposed to reactor 

coolant and neutron flux; 

Upper internals 

assembly: fuel alignment 

plate (applicable to 

plants with core shrouds 

assembled with full 

height shroud plates) 

exposed to reactor 

coolant and neutron flux; 

Lower support structure: 

core support plate 

(applicable to plants with 

a core support plate) 

exposed to reactor 

coolant and neutron flux

Cracking due to fatigue Chapter XI.M16A, “PWR 

Vessel Internals," and 

Chapter XI.M2, “Water 

Chemistry,” if fatigue life 

cannot be confirmed by 

TLAA

Yes, evaluate to 

determine the 

potential locations 

and extent of fatigue 

cracking (See 

subsection 

3.1.2.2.12) 

27 PWR Nickel alloy 

Westinghouse control 

rod guide tube 

assemblies, guide tube 

support pins exposed to 

reactor coolant and 

neutron flux

Cracking due to stress 

corrosion cracking and 

fatigue

A plant-specific aging 

management program is to 

be evaluated

Yes, plant-specific 

(See subsection 

3.1.2.2.13)
NUREG-1800, Rev. 2 3.1-26 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

28 PWR Nickel alloy 

Westinghouse control 

rod guide tube 

assemblies, guide tube 

support pins, and 

Zircaloy-4 Combustion 

Engineering incore 

instrumentation thimble 

tubes exposed to reactor 

coolant and neutron flux

Loss of material due to 

wear

A plant-specific aging 

management program is to 

be evaluated

Yes, plant-specific 

(See subsection 

3.1.2.2.14)

29 BWR Nickel alloy core shroud 

and core plate access 

hole cover (welded 

covers) exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water 

Chemistry,” and for BWRs 

with a crevice in the access 

hole covers, augmented 

inspection using UT or 

other acceptable 

techniques

No 

30 BWR Stainless steel or nickel 

alloy penetration: drain 

line exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water 

Chemistry”

No 

31 BWR Steel and stainless steel 

isolation condenser 

components exposed to 

reactor coolant

Loss of material due to 

general (steel only), 

pitting, and crevice 

corrosion

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water 

Chemistry”

No 
December 2010 3.1-27 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

32 PWR Stainless steel, nickel 

alloy, or CASS reactor 

vessel internals, core 

support structure, 

exposed to reactor 

coolant and neutron flux

Cracking, or loss of 

material due to wear

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD”

No 

33 PWR Stainless steel, steel 

with stainless steel 

cladding Class 1 reactor 

coolant pressure 

boundary components 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

ASME components, and 

Chapter XI.M2, “Water 

Chemistry” 

No 

34 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 stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

ASME components, and 

Chapter XI.M2, “Water 

Chemistry” 

No 

35 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

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components

No 
NUREG-1800, Rev. 2 3.1-28 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

36 PWR Steel, stainless steel 

pressurizer integral 

support exposed to air 

with metal temperature 

up to 288°C (550°F)

Cracking due to cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components

No 

37 PWR Steel reactor vessel 

flange

Loss of material due to 

wear

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components

No 

38 BWR/

PWR

Cast austenitic stainless 

steel Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250 deg-C 

(>482 deg-F)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components. For 

pump casings and valve 

bodies, screening for 

susceptibility to thermal 

aging is not necessary.

No 

39 BWR/

PWR

Steel, stainless steel, or 

steel with stainless steel 

cladding Class 1 piping, 

fittings and branch 

connections < NPS 4 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking (for 

stainless steel only), and 

thermal, mechanical, 

and vibratory loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, 

Chapter XI.M2, “Water 

Chemistry,” and 

XI.M35, "One-Time 

Inspection of ASME Code 

Class 1 Small-bore Piping"

No 
December 2010 3.1-29 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

40 PWR Steel with stainless steel 

or nickel alloy cladding; 

or stainless steel 

pressurizer components 

exposed to reactor 

coolant

Cracking due to cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry”

No 

PWR Nickel alloy core support 

pads; core guide lugs 

exposed to reactor 

coolant

Cracking 

due to primary water 

stress corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry”

No 

41 BWR Nickel alloy core shroud 

and core plate access 

hole cover (mechanical 

covers) exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry” 

No 

42 PWR Steel with stainless steel 

or nickel alloy cladding 

or stainless steel primary 

side components; steam 

generator upper and 

lower heads, and tube 

sheet weld; or 

pressurizer components 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry” 

No 
NUREG-1800, Rev. 2 3.1-30 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

43 BWR Stainless steel and 

nickel-alloy reactor 

vessel internals exposed 

to reactor coolant

Loss of material due to 

pitting and crevice 

corrosion

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 1 components, and 

Chapter XI.M2, “Water 

Chemistry” 

No 

44 PWR Steel steam generator 

secondary manways and 

handholds (cover only) 

exposed to air with 

leaking secondary-side 

water and/or steam

Loss of material due to 

erosion

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD” for 

Class 2 components

No 

45 PWR Nickel alloy and steel 

with nickel-alloy cladding 

reactor coolant pressure 

boundary components 

exposed to reactor 

coolant

Cracking due to primary 

water stress corrosion 

cracking

Chapter XI.M1, “ASME 

Section XI ISI, IWB, IWC & 

IWD,” and Chapter XI.M2, 

“Water Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking of 

Nickel-Alloy Components 

and Loss of Material Due to 

Boric Acid-induced 

Corrosion in RCPB 

Components (PWRs Only)"

No 
December 2010 3.1-31 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

46 PWR Stainless steel, nickelalloy, nickel-alloy welds 

and/or buttering control 

rod drive head 

penetration pressure 

housing or nozzles safe 

ends and welds (inlet, 

outlet, safety injection) 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI ISI, IWB, IWC & 

IWD,” and Chapter XI.M2, 

“Water Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking of 

Nickel-Alloy Components 

and Loss of Material Due to 

Boric Acid-induced 

corrosion in RCPB 

Components (PWRs Only)"

No 

47 PWR Stainless steel, nickelalloy control rod drive 

head penetration 

pressure housing 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Chapter XI.M1, “ASME 

Section XI ISI, IWB, IWC & 

IWD,” and Chapter XI.M2, 

“Water Chemistry”

No 

48 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

Chapter XI.M10, "Boric Acid 

Corrosion," and 

Chapter XI.M11B, 

"Cracking of Nickel-Alloy 

Components and Loss of 

Material Due to Boric AcidInduced Corrosion in RCPB 

Components (PWRs Only)"

No 
NUREG-1800, Rev. 2 3.1-32 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

49 PWR Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting exposed 

to air with borated water 

leakage

Loss of material due to 

boric acid corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No 

50 BWR/

PWR

Cast austenitic stainless 

steel Class 1 piping, 

piping component, and 

piping elements and 

control rod drive 

pressure housings 

exposed to reactor 

coolant >250 deg-C 

(>482 deg-F)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Chapter XI.M12, "Thermal 

Aging Embrittlement of Cast 

Austenitic Stainless Steel 

(CASS)"

No 

51 PWR Stainless steel or nickelalloy Babcock & Wilcox 

reactor internal 

components exposed to 

reactor coolant and 

neutron flux

Cracking due to stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking, or fatigue

Chapter XI.M16A, “PWR 

Vessel Internals," and 

Chapter XI.M2, “Water 

Chemistry”

No 
December 2010 3.1-33 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

52 PWR Stainless steel or nickelalloy Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron flux

Cracking due to stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking, or fatigue

Chapter XI.M16A, “PWR 

Vessel Internals," and 

Chapter XI.M2, “Water 

Chemistry”

No 

53 PWR Stainless steel or nickelalloy Westinghouse 

reactor internal 

components exposed to 

reactor coolant and 

neutron flux

Cracking due to stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking, or fatigue

Chapter XI.M16A, “PWR 

Vessel Internals," and 

Chapter XI.M2, “Water 

Chemistry”

No 
NUREG-1800, Rev. 2 3.1-34 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

54 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

Chapter XI.M16A, “PWR 

Vessel Internals,” and 

Chapter XI.M37, "Flux 

Thimble Tube Inspection"

No 

55 PWR Stainless steel thermal 

shield assembly, thermal 

shield flexures exposed 

to reactor coolant and 

neutron flux

Cracking due to fatigue; 

Loss of material due to 

wear

Chapter XI.M16A, “PWR 

Vessel Internals”

No 

56 PWR Stainless steel or nickelalloy Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement; or 

changes in dimension 

due to void swelling; or 

loss of preload due to 

thermal and irradiation 

enhanced stress 

relaxation; or loss of 

material due to wear

Chapter XI.M16A, “PWR 

Vessel Internals”

No 
December 2010 3.1-35 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

58 PWR Stainless steel or nickelalloy Babcock & Wilcox 

reactor internal 

components exposed to 

reactor coolant and 

neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement; or 

changes in dimension 

due to void swelling; or 

loss of preload due to 

thermal and irradiation 

enhanced stress 

relaxation; or loss of 

material due to wear

Chapter XI.M16A, “PWR 

Vessel Internals”

No 

59 PWR Stainless steel or nickelalloy Westinghouse 

reactor internal 

components exposed to 

reactor coolant and 

neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement; or 

changes in dimension 

due to void swelling; or 

loss of preload due to 

thermal and irradiation 

enhanced stress 

relaxation; or loss of 

material due to wear

Chapter XI.M16A, “PWR 

Vessel Internals”

No 

60 BWR Steel piping, piping 

components, and piping 

elements exposed to 

reactor coolant

Wall thinning due to 

flow-accelerated 

corrosion

Chapter XI.M17, “FlowAccelerated Corrosion”No 
NUREG-1800, Rev. 2 3.1-36 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

61 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 

flow-accelerated 

corrosion

Chapter XI.M17, “FlowAccelerated Corrosion”No 

62 PWR High-strength, low alloy 

steel, or stainless steel 

closure bolting; stainless 

steel control rod drive 

head penetration flange 

bolting exposed to air 

with reactor coolant 

leakage

Cracking due to stress 

corrosion cracking

Chapter XI.M18, "Bolting 

Integrity"

No 

63 BWR Steel or stainless steel 

closure bolting exposed 

to air with reactor 

coolant leakage

Loss of material due to 

general (steel only), 

pitting, and crevice 

corrosion or wear

Chapter XI.M18, "Bolting 

Integrity"

No 

64 PWR Steel closure bolting 

exposed to air – indoor 

uncontrolled

Loss of material due to 

general, pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting 

Integrity"

No 

65 PWR Stainless steel control 

rod drive head 

penetration flange 

bolting exposed to air 

with reactor coolant 

leakage

Loss of material due to 

wear

Chapter XI.M18, "Bolting 

Integrity"

No 
December 2010 3.1-37 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

66 PWR High-strength, low alloy 

steel, or stainless steel 

closure bolting; stainless 

steel control rod drive 

head penetration flange 

bolting exposed to air 

with reactor coolant 

leakage

Loss of preload due to 

thermal effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting 

Integrity"

No 

67 BWR/

PWR

Steel or stainless steel 

closure bolting exposed 

to air – indoor with 

potential for reactor 

coolant leakage

Loss of preload due to 

thermal effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting 

Integrity"

No 

68 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

Chapter XI.M19, “Steam 

Generators,” and Chapter

XI.M2, “Water Chemistry”

No 

69 PWR Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater or 

steam

Cracking due to outer 

diameter stress 

corrosion cracking and 

intergranular attack

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 

70 PWR Nickel alloy steam 

generator tubes, repair 

sleeves, and tube plugs 

exposed to reactor 

coolant

Cracking due to primary 

water stress corrosion 

cracking

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 
NUREG-1800, Rev. 2 3.1-38 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

71 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 stress 

corrosion cracking or 

other mechanism(s); 

loss of material due 

general (steel only), 

pitting, and crevice 

corrosion

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 

72 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 

erosion, general, pitting, 

and crevice corrosion, 

ligament cracking due to 

corrosion

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 

73 PWR Nickel alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry in 

secondary feedwater or 

steam

Loss of material due to 

wastage and pitting 

corrosion

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 

74 PWR Steel steam generator 

upper assembly and 

separators including 

feedwater inlet ring and 

support exposed to 

secondary feedwater or 

steam

Wall thinning due to 

flow-accelerated 

corrosion

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 

75 PWR Steel steam generator 

tube support lattice bars 

exposed to secondary 

feedwater or steam

Wall thinning due to 

flow-accelerated 

corrosion and general 

corrosion

Chapter XI.M19, “Steam 

Generators,” and Chapter 

XI.M2, “Water Chemistry”

No 
December 2010 3.1-39 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

76 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 

fretting

Chapter XI.M19, “Steam 

Generators”

No 

77 PWR Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater or 

steam

Loss of material due to 

wear and fretting

Chapter XI.M19, “Steam 

Generators”

No 

78 PWR Nickel alloy steam 

generator components 

such as, secondary side 

nozzles (vent, drain, and 

instrumentation) 

exposed to secondary 

feedwater or steam

Cracking due to stress 

corrosion cracking

Chapter XI.M2, "Water 

Chemistry," and Chapter 

XI.M32, "One-Time 

Inspection," or Chapter 

XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, and 

IWD.” 

No 

79 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 and crevice 

corrosion

Chapter XI.M2, "Water 

Chemistry," and Chapter 

XI.M32, "One-Time 

Inspection"

No 
NUREG-1800, Rev. 2 3.1-40 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

80 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 stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 

81 PWR Stainless steel

pressurizer spray head 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 

82 PWR Nickel alloy pressurizer 

spray head exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 

83 PWR Steel steam generator 

shell assembly exposed 

to secondary feedwater 

or steam

Loss of material due to 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 

84 BWR Steel top head enclosure 

(without cladding) top 

head nozzles (vent, top 

head spray or RCIC, and 

spare) exposed to 

reactor coolant

Loss of material due to 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 
December 2010 3.1-41 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

85 BWR Stainless steel, nickelalloy, 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 and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and Chapter 

XI.M32, “One-Time 

Inspection”

No 

86 PWR Stainless steel steam 

generator primary side 

divider plate exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry”

No 

87 PWR Stainless steel or nickelalloy PWR reactor 

internal components 

exposed to reactor 

coolant and neutron flux

Loss of material due to 

pitting and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry” 

No 

88 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 and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry”

No 

89 PWR Steel piping, piping 

components, and piping 

elements exposed to 

closed cycle cooling 

water

Loss of material due to 

general, pitting, and 

crevice corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 
NUREG-1800, Rev. 2 3.1-42 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

90 PWR Copper alloy piping, 

piping components, and 

piping elements exposed 

to closed cycle cooling 

water

Loss of material due to 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

91 BWR High-strength low alloy 

steel closure head stud 

assembly exposed to air 

with potential for reactor 

coolant leakage

Cracking due to stress 

corrosion cracking; loss 

of material due to 

general, pitting, and 

crevice corrosion, or 

wear (BWR)

Chapter XI.M3, “Reactor 

Head Closure Stud Bolting”

No 

92 PWR High-strength low alloy 

steel closure head stud 

assembly exposed to air 

with potential for reactor 

coolant leakage

Cracking due to stress 

corrosion cracking; loss 

of material due to 

general, pitting, and 

crevice corrosion, or 

wear (PWR)

Chapter XI.M3, “Reactor 

Head Closure Stud Bolting”

No 

93 PWR Copper alloy >15% Zn or 

> 8% Al piping, piping 

components, and piping 

elements exposed to 

closed cycle cooling 

water

Loss of material due to 

selective leaching

Chapter XI.M33, “Selective 

Leaching ”

No 

94 BWR Stainless steel and 

nickel alloy vessel shell 

attachment welds 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M4, “BWR 

Vessel ID Attachment 

Welds,” and Chapter XI.M2, 

“Water Chemistry”

No 

95 BWR Steel (with or without 

stainless steel cladding) 

feedwater nozzles 

exposed to reactor 

coolant

Cracking due to cyclic 

loading

Chapter XI.M5, “BWR 

Feedwater Nozzle”

No 
December 2010 3.1-43 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

96 BWR Steel (with or without 

stainless steel cladding) 

control rod drive return 

line nozzles exposed to 

reactor coolant

Cracking due to cyclic 

loading

Chapter XI.M6, “BWR 

Control Rod Drive Return 

Line Nozzle”

No 

97 BWR Stainless steel and 

nickel alloy piping, piping 

components, and piping 

elements greater than or 

equal to 4 NPS; nozzle 

safe ends and 

associated welds

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M7, “BWR 

Stress Corrosion Cracking,” 

and Chapter XI.M2, “Water 

Chemistry”

No 

98 BWR Stainless steel or nickel 

alloy penetrations:

instrumentation and 

standby liquid control 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, cyclic 

loading

Chapter XI.M8, “BWR 

Penetrations,” and Chapter 

XI.M2, “Water Chemistry”

No 

99 BWR Cast austenitic stainless 

steel; PH martensitic 

stainless steel; 

martensitic stainless 

steel; X-750 alloy reactor 

internal components 

exposed to reactor 

coolant and neutron flux

Loss of fracture 

toughness due to 

thermal aging and 

neutron irradiation 

embrittlement

Chapter XI.M9, "BWR 

Vessel Internals"

No 

100 BWR Stainless steel reactor 

vessel internals 

components (jet pump 

wedge surface) exposed 

to reactor coolant

Loss of material due to 

wear

Chapter XI.M9, "BWR 

Vessel Internals"

No 
NUREG-1800, Rev. 2 3.1-44 December 2010

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

101 BWR Stainless steel steam 

dryers exposed to 

reactor coolant

Cracking due to flowinduced vibrationChapter XI.M9, "BWR 

Vessel Internals" for steam 

dryer

No 

102 BWR Stainless steel fuel 

supports and control rod 

drive assemblies control 

rod drive housing 

exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M9, “BWR 

Vessel Internals,” and 

Chapter XI.M2, “Water 

Chemistry”

No 

103 BWR Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron flux

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Chapter XI.M9, “BWR 

Vessel Internals,” and 

Chapter XI.M2, “Water 

Chemistry”

No 

104 BWR X-750 alloy reactor 

vessel internal 

components exposed to 

reactor coolant and 

neutron flux

Cracking due to 

intergranular stress 

corrosion cracking

Chapter XI.M9, “BWR 

Vessel Internals” for core 

plate, and 

Chapter XI.M2, “Water 

Chemistry”

No 

105 BWR/

PWR

Steel piping, piping 

components and piping 

element exposed to 

concrete

None None, provided 1) attributes 

of the concrete are 

consistent with ACI 318 or 

ACI 349 (low water-tocement ratio, low 

permeability, and adequate 

air entrainment) as cited in 

NUREG-1557, and 2) plant 

OE indicates no 

degradation of the concrete

No, if conditions are 

met.
December 2010 3.1-45 NUREG-1800, Rev. 2

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

Chapter IV of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

106 BWR/

PWR

Nickel alloy piping, 

piping components and 

piping element exposed 

to air – indoor, 

uncontrolled, or air with 

borated water leakage

None None NA - No AEM or 

AMP

107 BWR/

PWR

Stainless steel piping, 

piping components and 

piping element exposed 

to gas, concrete, air with 

borated water leakage, 

air – indoors, 

uncontrolled

None None NA - No AEM or 

AMP
NUREG-1800, Rev. 2 3.1-46 December 2010

Table 3.1-2 Aging Management Programs Recommended for Reactor Vessel, 

Internals, and Reactor Coolant System

GALL Report Chapter/AMP Program Name

Chapter X.M1 Metal Fatigue of Reactor Coolant Pressure Boundary

Chapter XI.M1 ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD

Chapter XI.M2 Water Chemistry

Chapter XI.M3 Reactor Head Closure Stud Bolting

Chapter XI.M4 BWR Vessel ID Attachment Welds

Chapter XI.M5 BWR Feedwater Nozzle

Chapter XI.M6 BWR Control Rod Drive Return Line Nozzle

Chapter XI.M7 BWR Stress Corrosion Cracking

Chapter XI.M8 BWR Penetrations

Chapter XI.M9 BWR Vessel Internals

Chapter XI.M10 Boric Acid Corrosion

Chapter 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)

Chapter XI.M12 Thermal Aging of Cast Austenitic Stainless Steel 

(CASS)

Chapter XI.M16A PWR Vessel Internals

Chapter XI.M17 Flow-Accelerated Corrosion

Chapter XI.M18 Bolting Integrity

Chapter XI.M19 Steam Generators

Chapter XI.M21A Closed Treated Water Systems

Chapter XI.M31 Reactor Vessel Surveillance

Chapter XI.M32 One-Time Inspection

Chapter XI.M33 Selective Leaching

Chapter XI.M35 One-Time Inspection of ASME Code Class 1 Small 

Bore-Piping

Chapter XI.M37 Flux Thimble Tube Inspection

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP
December 2010 3.2-1 NUREG-1800, Rev. 2

3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES

Review Responsibilities

Primary - Branch assigned responsibility by PM as described in SRP-LR Section 3.0 of this 

SRP-LR.

3.2.1 Areas of Review

This section addresses the aging management review (AMR) and the associated aging 

management program (AMP) 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 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 Final Safety Analysis Report (FSAR) may have predated NUREG-0800. 

The engineered safety features consist of containment spray, standby gas treatment [Boiling 

Water Reactors (BWRs)], containment isolation components, and emergency core cooling 

systems.

The responsible review organization is to review the following license renewal application (LRA) 

AMR and AMP items assigned to it, per SRP-LR Section 3.0:

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL 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 NRC’s regulations in 10 CFR 54.21.

3.2.2.1 AMR Results Consistent with the GALL Report 

The AMR and the AMPs applicable to the engineered safety features are described and 

evaluated in Chapter V of NUREG-1801 (GALL Report).
NUREG-1800, Rev. 2 3.2-2 December 2010

The applicant’s LRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific LRA AMR item and the associated LRA AMP are consistent with the 

cited GALL Report AMR item. The reviewer should then confirm that the LRA AMR item is 

consistent with the GALL Report AMR item to which it is compared.

When the applicant is crediting a different aging management program than recommended in 

the GALL Report, the reviewer should confirm that the alternate aging management program is 

valid to use for aging management and will be capable of managing the effects of aging as 

adequately as the aging management program recommended by the GALL Report.

3.2.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to 

which the LRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply as identified by the GALL Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.2-1, comparing the “Further Evaluation 

Recommended” and the “Rev2 Item” columns, for the AMR items that reference the following 

subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.2.2.2.1 Cumulative Fatigue Damage 

Fatigue 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). This TLAA is addressed separately in 

Section 4.3, “Metal Fatigue Analysis,” of this SRP-LR. 

3.2.2.2.2 Loss of Material due to Cladding Breach

Loss of material due to cladding breach could occur for PWR steel pump casings with stainless 

steel cladding exposed to treated borated water. The GALL Report references NRC Information 

Notice 94-63, Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks, and 

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is 

adequately managed. Acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR).

3.2.2.2.3 Loss of Material due to Pitting and Crevice Corrosion 

1. Loss of material due to pitting and crevice corrosion could occur in partially encased 

stainless steel tanks exposed to raw water due to cracking of the perimeter seal from 

weathering. The GALL Report recommends further evaluation to ensure that the aging 

effect is adequately managed. The GALL Report recommends that a plant-specific AMP 

be evaluated because moisture and water can egress under the tank if the perimeter 

seal is degraded. Acceptance criteria are described in Branch Technical Position 

RSLB-1 (Appendix A.1 of this SRP-LR).

2. Loss of material due to pitting and crevice corrosion could occur for stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air. The 

possibility of pitting and crevice corrosion also extends to components exposed to air 

which has recently been introduced into buildings, i.e., components near intake vents. 

Pitting and crevice corrosion is only known to occur in environments containing sufficient 
December 2010 3.2-3 NUREG-1800, Rev. 2

halides (primarily chlorides) and in which condensation or deliquescence is possible.

Condensation or deliquescence should generally be assumed to be possible. Applicable 

outdoor air environments (and associated indoor air environments) include, but are not 

limited to, those within approximately 5 miles of a saltwater coastline, those within 1/2 

mile of a highway which is treated with salt in the wintertime, those areas in which the 

soil contains more than trace chlorides, those plants having cooling towers where the 

water is treated with chlorine or chlorine compounds, and those areas subject to chloride 

contamination from other agricultural or industrial sources. This item is applicable for the 

environments described above.

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage 

the aging effect. The applicant may demonstrate that this item is not applicable by 

describing the outdoor air environment present at the plant and demonstrating that 

external pitting or crevice corrosion is not expected. The GALL Report recommends 

further evaluation to determine whether an aging management program is needed to 

manage this aging effect based on the environmental conditions applicable to the plant 

and requirements applicable to the components.

3.2.2.2.4 Loss of Material due to Erosion 

Loss of material due to erosion could occur in the stainless steel high-pressure safety injection 

(HPSI) pump miniflow recirculation orifice exposed to treated borated water. The GALL Report 

recommends a plant-specific AMP be evaluated for erosion of the orifice due to extended use of 

the centrifugal HPSI pump for normal charging. The GALL Report references Licensee Event 

Report (LER) 50-275/94-023 for evidence of erosion. Further evaluation is recommended to 

ensure that the aging effect is adequately managed. Acceptance criteria are described in 

Branch Technical Position RSLB-1 (Appendix A.1 of this SRP-LR).

3.2.2.2.5 Loss of Material due to General Corrosion and Fouling that Leads to 

Corrosion

Loss of material due to general corrosion and fouling that leads to corrosion can occur for steel 

drywell and suppression chamber spray system nozzle and flow orifice internal surfaces 

exposed to air - indoor uncontrolled. This could result in plugging of the spray nozzles and flow 

orifices. This aging mechanism and effect will apply since the spray nozzles and flow orifices 

are occasionally wetted, even though the majority of the time this system is on standby. The 

wetting and drying of these components can accelerate corrosion and fouling. The GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is 

adequately managed. Acceptance criteria are described in Branch Technical Position RSLB-1 

(Appendix A.1 of this SRP-LR).

3.2.2.2.6 Cracking due to Stress Corrosion Cracking 

Cracking due to stress corrosion cracking could occur for stainless steel piping, piping 

components, piping elements and tanks exposed to outdoor air. The possibility of cracking also 

extends to components exposed to air which has recently been introduced into buildings, i.e., 

components near intake vents. Cracking is only known to occur in environments containing 

sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible. 

Condensation or deliquescence should generally be assumed to be possible. Applicable 

outdoor air environments (and associated indoor air environments) include, but are not limited 

to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a 
NUREG-1800, Rev. 2 3.2-4 December 2010

highway which is treated with salt in the wintertime, those areas in which the soil contains more 

than trace chlorides, those plants having cooling towers where the water is treated with chlorine 

or chlorine compounds, and those areas subject to chloride contamination from other 

agricultural or industrial sources. This item is applicable for the environments described above. 

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the 

aging effect. The applicant may demonstrate that this item is not applicable by describing the 

outdoor air environment present at the plant and demonstrating that external chloride stress 

corrosion cracking is not expected. The GALL Report recommends further evaluation to 

determine whether an aging management program is needed to manage this aging effect based 

on the environmental conditions applicable to the plant and requirements applicable to the 

components.

3.2.2.2.7 Quality Assurance for Aging Management of Nonsafety-Related Components

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2 of this 

SRP-LR.)

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

Acceptance criteria are described in Branch Technical Position RSLB-1 (Appendix A.1 of this 

SRP-LR).

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 Report, the NRC reviewer performs an audit of aging 

management programs credited in the LRA to confirm consistency with the GALL AMPs 

identified in the GALL Report, Chapters X and XI.

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP with all 

exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, the 

reviewer identifies a difference between the LRA AMP and the GALL Report AMP that should 

have been identified as an exception to the GALL Report AMP, the difference should be 

reviewed and properly dispositioned. The reviewer should document the disposition of all LRAdefined exceptions and staff-identified differences.

The LRA should identify any enhancements that are needed to permit an existing AMP to be 

declared consistent with the GALL Report AMP to which the LRA 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 Report AMP and also that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the 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 AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1.2.3 of this SRP-LR).
December 2010 3.2-5 NUREG-1800, Rev. 2

3.2.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

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 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 3.0-1 of this SRP-LR provides 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-LR subsection.

3.2.3 Review Procedures

For each area of review, the following review procedures are to be followed:

3.2.3.1 AMR Results Consistent with the GALL Report

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to the GALL Report in its LRA. 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 applicant 

has stated that the applicable aging effects and industry and plant-specific operating experience 

have been reviewed by the applicant and are evaluated in the GALL Report.

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL Report. Performance of this review requires 

the reviewer to confirm that the applicant has identified those aging effects for the engineered 

safety features system components that are contained in the GALL Report as applicable to its 

plant.

3.2.3.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to which the 

LRA AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL Report for each of the following aging effect/aging 

mechanism combinations.

3.2.3.2.1 Cumulative Fatigue Damage 

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). The staff reviews the evaluation of this TLAA separately, 

following the guidance in Section 4.3 of this SRP-LR.
NUREG-1800, Rev. 2 3.2-6 December 2010

3.2.3.2.2 Loss of Material due to Cladding Breach

The GALL Report recommends further evaluation of programs to manage loss of material due 

to cladding breach for PWR steel charging pump casings with stainless steel cladding. The 

GALL Report references NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump 

Casings Caused by Cladding Cracks, and recommends further evaluation of a plant-specific 

program to ensure that the aging effect is adequately managed. 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 general corrosion of these components.

3.2.3.2.3 Loss of Material due to Pitting and Crevice Corrosion 

1. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for partially encased stainless steel tanks 

exposed to raw water. The GALL Report specifically recommends that the program 

address the bottom of partially encased stainless steel tanks because moisture and 

water can egress under the tank due to cracking of the perimeter seal from weathering. 

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 pitting and crevice corrosion of these components

2. The GALL Report recommends further evaluation to manage loss of material due to 

pitting and crevice corrosion of stainless steel piping, piping components, piping 

elements, and tanks exposed to outdoor air environments containing sufficient halides 

(primarily chlorides) and in which condensation or deliquescence is possible. The 

possibility of pitting and crevice corrosion also extends to components exposed to air 

which has recently been introduced into buildings, i.e., components near intake vents.

The reviewer should determine whether an adequate program is credited to manage the 

aging effect based on the applicable environmental conditions. Pitting and crevice 

corrosion is only known to occur in environments containing sufficient halides (primarily 

chlorides) and in which condensation or deliquescence is possible. Condensation or 

deliquescence should generally be assumed to be possible. Applicable outdoor air 

environments (and associated indoor air environments) include, but are not limited to, 

those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a 

highway which is treated with salt in the wintertime, those areas in which the soil 

contains more than trace chlorides, those plants having cooling towers where the water 

is treated with chlorine or chlorine compounds, and those areas subject to chloride 

contamination from other agricultural or industrial sources. This item is applicable for the 

environments described above. The use of GALL AMP XI.M36, “External Surfaces 

Monitoring,” is an acceptable method to manage the aging effect.

3.2.3.2.4 Loss of Material due to Erosion 

The GALL Report recommends further evaluation of programs to manage loss of material due 

to erosion of the stainless steel high pressure safety injection pump miniflow orifice. The 

reviewer reviews the applicant’s proposed program on a case-by-case basis to ensure that an 

adequate program will be in place to manage this aging effect.
December 2010 3.2-7 NUREG-1800, Rev. 2

3.2.3.2.5 Loss of Material due to General Corrosion and Fouling that Leads to 

Corrosion

The GALL Report recommends further evaluation of programs to manage loss of material due 

to general corrosion and fouling that leads to corrosion for steel drywell and suppression 

chamber spray system spray nozzles and orifices exposed to air - indoor uncontrolled. This is 

necessary to prevent the plugging of spray nozzles and spargers of the BWR drywell and 

suppression chamber spray system. 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 fouling of these components.

3.2.3.2.6 Cracking due to Stress Corrosion Cracking 

The GALL Report recommends further evaluation to manage cracking due to stress corrosion 

cracking of stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air environments containing sufficient halides (primarily chlorides) and in which 

condensation or deliquescence 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. 

The reviewer should determine whether an adequate program is credited to manage the aging 

effect based on the applicable environmental conditions. Cracking is only known to occur in 

environments containing sufficient halides (primarily chlorides) and in which condensation or 

deliquescence is possible. Condensation or deliquescence should generally be assumed to be 

possible. Applicable outdoor air environments (and associated indoor air environments) include, 

but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 

1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil 

contains more than trace chlorides, those plants having cooling towers where the water is 

treated with chlorine or chlorine compounds, and those areas subject to chloride contamination 

from other agricultural or industrial sources. This item is applicable for the environments 

described above. The use of GALL AMP XI.M36, “External Surfaces Monitoring,” is an 

acceptable method to manage the aging effect.

3.2.3.2.7 Quality Assurance for Aging Management of Nonsafety-Related Components

The applicant’s AMPs for license renewal 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 aging 

management review for license renewal. 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.

3.2.3.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

The reviewer should confirm that the applicant, in its LRA, 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 
NUREG-1800, Rev. 2 3.2-8 December 2010

is described and evaluated in the GALL Report or a plant-specific program. Review procedures 

are described in Branch Technical Position RSLB-1 (Appendix A.1 of this SRP-LR).

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA 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 LRA, between the LRA AMP and the GALL Report AMP, with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA 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 Report pertinent to the engineered safety 

features components are summarized in Table 3.2-1 of this SRP-LR. The “Rev2 Item” (for 2010) 

and “Rev1 Item” (for 2005 counterpart) columns identify the AMR item numbers in the GALL 

Report, Chapter V, presenting detailed information summarized by this row.

Table 3.2-1 of this SRP-LR may identify a plant-specific aging management program. If the 

applicant chooses to use a plant-specific program that is not a GALL AMP, the NRC reviewer 

should confirm that the plant-specific program satisfies the criteria of Branch Technical Position 

RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.2.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in its FSAR supplement information 

equivalent to that in Table 3.0-1 for aging management of the engineered safety features. Table 

3.2-2 lists the AMPs that are applicable for this SRP-LR subsection. The reviewer also confirms 

that the applicant has provided information for Subsection 3.2.3.3, “AMR Results Not Consistent 

With or Not Addressed in the GALL Report,” equivalent to that in Table 3.0-1.

The 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 and finds it acceptable 

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.

As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the LRA to any future aging management activities, including enhancements and commitments, 

to be completed before entering the period of extended operation. The 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.
December 2010 3.2-9 NUREG-1800, Rev. 2

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 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 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 in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.

3.2.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants, LWR Edition” U.S. Nuclear Regulatory Commission, March 2007.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

3. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.
NUREG-1800, Rev. 2 3.2-10 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

1 BWR/PWR Stainless steel, Steel Piping, 

piping components, and piping 

elements exposed to Treated 

water (borated)

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited 

aging analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See the SRP, 

Section 4.3 “Metal 

Fatigue,” for acceptable 

methods for meeting the 

requirements of 10 CFR 

54.21(c)(1).

Yes, TLAA (See 

subsection 

3.2.2.2.1)

2 PWR Steel (with stainless steel 

cladding) Pump casings exposed 

to Treated water (borated)

Loss of material 

due to cladding 

breach

A plant-specific aging 

management program is 

to be evaluated 

Reference NRC 

Information Notice 94-

63, “Boric Acid Corrosion 

of Charging Pump 

Casings Caused by 

Cladding Cracks."

Yes, verify that 

plant-specific 

program 

addresses clad 

breach (See 

subsection 

3.2.2.2.2)

3 PWR Stainless steel Partially-encased 

tanks with breached moisture 

barrier exposed to Raw water

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific aging 

management program is 

to be evaluated for 

pitting and crevice 

corrosion of tank bottom 

because moisture and 

water can egress under 

the tank due to cracking 

of the perimeter seal 

from weathering.

Yes, plantspecific (See 

subsection 

3.2.2.2.3.1)
December 2010 3.2-11 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

4 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements; tanks exposed to Air –

outdoor

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

Yes, 

environmental 

conditions need 

to be evaluated 

(See subsection 

3.2.2.2.3.2)

5 PWR Stainless steel Orifice (miniflow 

recirculation) exposed to Treated 

water (borated)

Loss of material 

due to erosion

A plant-specific aging 

management program is 

to be evaluated for 

erosion of the orifice due 

to extended use of the 

centrifugal HPSI pump 

for normal charging. See 

LER 50-275/94-023 for 

evidence of erosion.

Yes, plantspecific (See 

subsection 

3.2.2.2.4)

6 BWR Steel Drywell and suppression 

chamber spray system (internal 

surfaces): flow orifice; spray 

nozzles exposed to Air – indoor, 

uncontrolled (Internal)

Loss of material 

due to general 

corrosion; fouling 

that leads to 

corrosion

A plant-specific aging 

management program is 

to be evaluated

Yes, plantspecific (See 

subsection 

3.2.2.2.5)

7 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements; tanks exposed to Air –

outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

Yes, 

environmental 

conditions need 

to be evaluated 

(See subsection 

3.2.2.2.6)

8 PWR Aluminum, Copper alloy (>15% 

Zn or >8% Al) Piping, piping 

components, and piping 

elements exposed to Air with 

borated water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric 

Acid Corrosion”

No 
NUREG-1800, Rev. 2 3.2-12 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

9 PWR Steel External surfaces, Bolting 

exposed to Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric 

Acid Corrosion”

No 

10 BWR/PWR Cast austenitic stainless steel 

Piping, piping components, and 

piping elements exposed to 

Treated water (borated) >250°C 

(>482°F), Treated water >250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal aging 

embrittlement

Chapter XI.M12, 

"Thermal Aging 

Embrittlement of Cast 

Austenitic Stainless 

Steel (CASS)"

No 

11 BWR Steel Piping, piping components, 

and piping elements exposed to 

Steam, Treated water

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “FlowAccelerated Corrosion”No 

12 BWR/PWR Steel, high-strength Closure 

bolting exposed to Air with steam 

or water leakage

Cracking 

due to cyclic loading, 

stress corrosion 

cracking

Chapter XI.M18, "Bolting 

Integrity"

No 

13 BWR/PWR Steel; stainless steel Bolting, 

Closure bolting exposed to Air –

outdoor (External), Air – indoor, 

uncontrolled (External)

Loss of material 

due to general (steel 

only), pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting 

Integrity"

No 

14 BWR/PWR Steel Closure bolting exposed to 

Air with steam or water leakage

Loss of material 

due to general 

corrosion

Chapter XI.M18, "Bolting 

Integrity"

No 
December 2010 3.2-13 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

15 BWR/PWR Copper alloy, Nickel alloy, Steel; 

stainless steel, Stainless steel, 

Steel; stainless steel Bolting, 

Closure bolting exposed to Any 

environment, Air – outdoor 

(External), Raw water, Treated 

borated water, Fuel oil, Treated 

water, Air – indoor, uncontrolled 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting 

Integrity"

No 

16 BWR/PWR Steel Containment isolation 

piping and components (Internal 

surfaces), Piping, piping 

components, and piping 

elements exposed to Treated 

water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

17 BWR Aluminum, Stainless steel 

Piping, piping components, and 

piping elements exposed to 

Treated water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

18 BWR/PWR Stainless steel Containment 

isolation piping and components 

(Internal surfaces) exposed to 

Treated water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

19 BWR/PWR Stainless steel Heat exchanger 

tubes exposed to Treated water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 
NUREG-1800, Rev. 2 3.2-14 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

20 PWR Stainless steel Piping, piping 

components, and piping 

elements; tanks exposed to 

Treated water (borated) >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry”

No 

21 PWR Steel (with stainless steel or 

nickel-alloy cladding) Safety 

injection tank (accumulator) 

exposed to Treated water 

(borated) >60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry”

No 

22 PWR Stainless steel Piping, piping 

components, and piping 

elements; tanks exposed to 

Treated water (borated)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry”

No 

23 BWR/PWR Steel Heat exchanger 

components, Containment 

isolation piping and components 

(Internal surfaces) exposed to 

Raw water

Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "OpenCycle Cooling Water 

System"

No 

24 PWR Stainless steel Piping, piping 

components, and piping 

elements exposed to Raw water

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M20, "OpenCycle Cooling Water 

System"

No 
December 2010 3.2-15 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

25 BWR/PWR Stainless steel Heat exchanger 

components, Containment 

isolation piping and components 

(Internal surfaces) exposed to 

Raw water

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "OpenCycle Cooling Water 

System"

No 

26 BWR Stainless steel Heat exchanger 

tubes exposed to Raw water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "OpenCycle Cooling Water 

System"

No 

27 BWR/PWR Stainless steel, Steel Heat 

exchanger tubes exposed to 

Raw water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "OpenCycle Cooling Water 

System"

No 

28 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements exposed to Closedcycle cooling water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

29 BWR/PWR Steel Piping, piping components, 

and piping elements exposed to 

Closed-cycle cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

30 BWR/PWR Steel Heat exchanger 

components exposed to Closedcycle cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 
NUREG-1800, Rev. 2 3.2-16 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

31 BWR/PWR Stainless steel Heat exchanger 

components, Piping, piping 

components, and piping 

elements exposed to Closedcycle cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

32 BWR/PWR Copper alloy Heat exchanger 

components, Piping, piping 

components, and piping 

elements exposed to Closedcycle cooling water

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

33 BWR/PWR Copper alloy, Stainless steel 

Heat exchanger tubes exposed 

to Closed-cycle cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

34 BWR/PWR Copper alloy (>15% Zn or >8% 

Al) Piping, piping components, 

and piping elements, Heat 

exchanger components exposed 

to Closed-cycle cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No 

35 PWR Gray cast iron Motor cooler 

exposed to Treated water

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No 

36 PWR Gray cast iron Piping, piping 

components, and piping 

elements exposed to Closedcycle cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No 
December 2010 3.2-17 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

37 BWR/PWR Gray cast iron Piping, piping 

components, and piping 

elements exposed to Soil

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No 

38 BWR Elastomers Elastomer seals and 

components exposed to Air –

indoor, uncontrolled (External)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

No 

39 BWR/PWR Steel Containment isolation 

piping and components (External 

surfaces) exposed to 

Condensation (External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

No 

40 BWR/PWR Steel Ducting, piping, and 

components (External surfaces), 

Ducting, closure bolting, 

Containment isolation piping and 

components (External surfaces) 

exposed to Air – indoor, 

uncontrolled (External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

No 

41 BWR/PWR Steel External surfaces exposed 

to Air – outdoor (External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

No 

42 BWR/PWR Aluminum Piping, piping 

components, and piping 

elements exposed to Air -

outdoor

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of Mechanical 

Components"

No 
NUREG-1800, Rev. 2 3.2-18 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

43 BWR Elastomers Elastomer seals and 

components exposed to Air –

indoor, uncontrolled (Internal)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

44 BWR/PWR Steel Piping and components 

(Internal surfaces), Ducting and 

components (Internal surfaces) 

exposed to Air – indoor, 

uncontrolled (Internal)

Loss of material 

due to general 

corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

45 PWR Steel Encapsulation components 

exposed to Air – indoor, 

uncontrolled (Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

46 BWR Steel Piping and components 

(Internal surfaces) exposed to 

Condensation (Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

47 PWR Steel Encapsulation components 

exposed to Air with borated 

water leakage (Internal)

Loss of material 

due to general, 

pitting, crevice, and 

boric acid corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 
December 2010 3.2-19 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

48 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements (Internal surfaces); 

tanks exposed to Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

49 BWR/PWR Steel Piping, piping components, 

and piping elements exposed to 

Lubricating oil

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection”

No 

50 BWR/PWR Copper alloy, Stainless steel 

Piping, piping components, and 

piping elements exposed to 

Lubricating oil

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection”

No 

51 BWR/PWR Steel, Copper alloy, Stainless 

steel Heat exchanger tubes 

exposed to Lubricating oil

Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection”

No 

52 BWR/PWR Steel (with coating or wrapping) 

Piping, piping components, and 

piping elements exposed to Soil

or Concrete

Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M41, "Buried 

and Underground Piping 

and Tanks"

No 
NUREG-1800, Rev. 2 3.2-20 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

53 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements exposed to Soil or 

Concrete

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried 

and Underground Piping 

and Tanks"

No 

BWR/PWR Steel; stainless steel 

Underground piping, piping 

components, and piping 

elements exposed to air-indoor 

uncontrolled or condensation 

(external) 

Loss of material due 

to general (steel 

only), pitting and 

crevice corrosion

Chapter XI.M41, "Buried 

and Underground Piping 

and Tanks"

No 

54 BWR Stainless steel Piping, piping 

components, and piping 

elements exposed to Treated 

water >60°C (>140°F)

Cracking 

due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M7, “BWR 

Stress Corrosion 

Cracking,” and 

Chapter XI.M2, “Water 

Chemistry”

No 

55 BWR/PWR Steel Piping, piping components, 

and piping elements exposed to 

Concrete

None None, provided 

1) attributes of the 

concrete are consistent 

with ACI 318 or ACI 349 

(low water-to-cement 

ratio, low permeability, 

and adequate air 

entrainment) as cited in 

NUREG-1557, and 

2) plant OE indicates no 

degradation of the 

concrete

No, if conditions 

are met.
December 2010 3.2-21 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

56 BWR/PWR Aluminum Piping, piping 

components, and piping 

elements exposed to Air –

indoor, uncontrolled 

(Internal/External)

None None NA - No AEM or 

AMP

57 BWR/PWR Copper alloy Piping, piping 

components, and piping 

elements exposed to Air –

indoor, uncontrolled (External), 

Gas

None None NA - No AEM or 

AMP

58 PWR Copper alloy (≤15% Zn and ≤8% 

Al) Piping, piping components, 

and piping elements exposed to 

Air with borated water leakage

None None NA - No AEM or 

AMP

59 BWR/PWR Galvanized steel Ducting, piping, 

and components exposed to Air 

– indoor, controlled (External)

None None NA - No AEM or 

AMP

60 BWR/PWR Glass Piping elements exposed 

to Air – indoor, uncontrolled 

(External), Lubricating oil, Raw 

water, Treated water, Treated 

water (borated), Air with borated 

water leakage, Condensation 

(Internal/External), Gas, Closedcycle cooling water, Air –

outdoor

None None NA - No AEM or 

AMP

61 BWR/PWR Nickel alloy Piping, piping 

components, and piping 

elements exposed to Air –

indoor, uncontrolled (External)

None None NA - No AEM or 

AMP
NUREG-1800, Rev. 2 3.2-22 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management

Programs

Further 

Evaluation 

Recommended

62 BWR/PWR Nickel alloy Piping, piping 

components, and piping 

elements exposed to Air with 

borated water leakage

None None NA - No AEM or 

AMP

63 BWR/PWR Stainless steel Piping, piping 

components, and piping 

elements exposed to Air –

indoor, uncontrolled (External), 

Air with borated water leakage, 

Concrete, Gas, Air – indoor, 

uncontrolled (Internal)

None None NA - No AEM or 

AMP

64 BWR/PWR Steel Piping, piping components, 

and piping elements exposed to 

Air – indoor, controlled 

(External), Gas

None None NA - No AEM or 

AMP
December 2010 3.2-23 NUREG-1800, Rev. 2

Table 3.2-2 Aging Management Programs Recommended for Engineered Safety 

Features

GALL Report Chapter/AMP Program Name

Chapter XI.M2 Water Chemistry

Chapter XI.M7 BWR Stress Corrosion Cracking

Chapter XI.M10 Boric Acid Corrosion

Chapter XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel 

(CASS)

Chapter XI.M17 Flow-Accelerated Corrosion (FAC)

Chapter XI.M18 Bolting Integrity 

Chapter XI.M20 Open-Cycle Cooling Water System 

Chapter XI.M21A Closed Treated Water Systems

Chapter XI.M32 One-Time Inspection

Chapter XI.M33 Selective Leaching

Chapter XI.M36 External Surfaces Monitoring of Mechanical Components

Chapter XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components

Chapter XI.M39 Lubricating Oil Analysis

Chapter XI.M41 Buried and Underground Piping and Tanks

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP

December 2010 3.3-1 NUREG-1800, Rev 2

3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS

Review Responsibilities

Primary - Branch assigned responsibility by PM as described in SRP-LR Section 3.0 of this 

SRP-LR.

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 license renewal. For a recent vintage 

plant, the information related to the auxiliary systems contained in Chapter 9, “Auxiliary 

Systems,” of the plant’s 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 NUREG0800 except for refueling water, chilled water, heat removal, condenser circulating water, and 

condensate storage system. For older plants, the location of applicable information is plantspecific because an older plant’s FSAR may have predated NUREG-0800. 

Typical auxiliary systems that are subject to an AMR for license renewal are new fuel storage, 

spent fuel storage, spent fuel pool cooling and cleanup (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 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 non-safety 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 SRP-LR 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 aging management program 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 license renewal application (LRA) 

AMR and AMP items assigned to it, per SRP-LR Section 3.0:

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report
NUREG-1800, Rev. 2 3.3-2 December 2010

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL 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 NRC’s regulations in 10 CFR 54.21.

3.3.2.1 AMR Results Consistent with the GALL Report

The AMR and the AMPs applicable to the auxiliary system features are described and evaluated 

in Chapter VII of NUREG-1801 (GALL Report).

The applicant’s LRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific LRA AMR item and the associated LRA AMP are consistent with the 

cited GALL Report AMR item. The reviewer should then confirm that the LRA AMR item is 

consistent with the GALL Report AMR item to which it is compared. 

When the applicant is crediting a different aging management program than recommended in 

the GALL Report, the reviewer should confirm that the alternate aging management program is 

valid to use for aging management and will be capable of managing the effects of aging as 

adequately as the aging management program recommended by the GALL Report. 

3.3.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item

to which the LRA AMR item is compared identifies that “further evaluation is recommended,” 

then additional criteria apply as identified by the GALL Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.3-1, comparing the “Further Evaluation 

Recommended” and the “Rev2 Item” columns, for the AMR items that reference the following 

subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.3.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). This TLAA is addressed separately in Section 4.3, “Metal 

Fatigue Analysis,” or Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses,” of this 

SRP-LR. 
December 2010 3.3-3 NUREG-1800, Rev 2

3.3.2.2.2 Cracking due to Stress Corrosion Cracking and Cyclic Loading 

Cracking due to SCC and cyclic loading could occur in stainless steel PWR non-regenerative 

heat exchanger components exposed to treated borated water greater than 60°C (>140°F) in 

the chemical and volume control system. The existing aging management program on 

monitoring and control of primary water chemistry in PWRs 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. The GALL Report recommends that a 

plant-specific aging management program be evaluated to verify the absence of cracking due to 

SCC and cyclic loading to ensure that these aging effects are managed adequately. An 

acceptable verification program is to include temperature and radioactivity monitoring of the 

shell side water, and eddy current testing of tubes. 

3.3.2.2.3 Cracking due to Stress Corrosion Cracking 

Cracking due to stress corrosion cracking could occur for stainless steel piping, piping 

components, piping elements and tanks exposed to outdoor air. The possibility of cracking also 

extends to components exposed to air which has recently been introduced into buildings, i.e., 

components near intake vents. Cracking is only known to occur in environments containing 

sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible. 

Condensation or deliquescence should generally be assumed to be possible. Applicable 

outdoor air environments (and associated indoor air environments) include, but are not limited 

to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a 

highway which is treated with salt in the wintertime, those areas in which the soil contains more 

than trace chlorides, those plants having cooling towers where the water is treated with chlorine 

or chlorine compounds, and those areas subject to chloride contamination from other 

agricultural or industrial sources. This item is applicable for the environments described above. 

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the 

aging effect. The applicant may demonstrate that this item is not applicable by describing the 

outdoor air environment present at the plant and demonstrating that external chloride stress 

corrosion cracking is not expected. The GALL Report recommends further evaluation to 

determine whether an adequate aging management program is used to manage this aging 

effect based on the environmental conditions applicable to the plant and ASME Code Section XI 

requirements applicable to the components.

3.3.2.2.4 Loss of Material due to Cladding Breach 

Loss of material due to cladding breach could occur for PWR steel charging pump casings with 

stainless steel cladding exposed to treated borated water. The GALL Report references NRC 

Information Notice 94-63, “Boric Acid Corrosion of Charging Pump Casings Caused by Cladding 

Cracks,” and recommends further evaluation of a plant-specific aging management program to 

ensure that the aging effect is adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

3.3.2.2.5 Loss of Material due to Pitting and Crevice Corrosion

Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, piping 

components, piping elements, and tanks exposed to outdoor air. The possibility of pitting and 

crevice corrosion also extends to components exposed to air which has recently been 
NUREG-1800, Rev. 2 3.3-4 December 2010

introduced into buildings, i.e., components near intake vents. Pitting and crevice corrosion is 

only known to occur in environments containing sufficient halides (primarily chlorides) and in 

which condensation or deliquescence is possible. Condensation or deliquescence should 

generally be assumed to be possible. Applicable outdoor air environments (and associated 

indoor air environments) include, but are not limited to, those within approximately 5 miles of a 

saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the 

wintertime, those areas in which the soil contains more than trace chlorides, those plants having 

cooling towers where the water is treated with chlorine or chlorine compounds, and those areas 

subject to chloride contamination from other agricultural or industrial sources. This item is 

applicable for the environments described above.

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the 

aging effect. The applicant may demonstrate that this item is not applicable by describing the 

outdoor air environment present at the plant and demonstrating that external pitting or crevice 

corrosion is not expected. The GALL Report recommends further evaluation to determine 

whether an adequate aging management program is used to manage this aging effect based on 

the environmental conditions applicable to the plant and ASME Code Section XI requirements 

Quality Assurance for Aging Management of Nonsafety-Related Components.

3.3.2.2.6 Quality Assurance for Aging Management of Nonsafety-Related Components

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2, of this 

SRP-LR.)

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR.)

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 Report, the NRC reviewer performs an audit of aging 

management programs credited in the LRA to confirm consistency with the GALL AMPs 

identified in the GALL Report, Chapters X and XI.

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP with all 

exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, the 

reviewer identifies a difference between the LRA AMP and the GALL Report AMP that should 

have been identified as an exception to the GALL Report AMP, the difference should be 

reviewed and properly dispositioned. The reviewer should document the disposition of all LRAdefined exceptions and staff-identified differences. 

The LRA should identify any enhancements that are needed to permit an existing LRA AMP to 

be declared consistent with the GALL Report AMP to which the LRA AMP is compared. The 

reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

LRA AMP to be consistent with the GALL Report AMP and also that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the period of 

extended operation. The reviewer should document the disposition of all enhancements.
December 2010 3.3-5 NUREG-1800, Rev 2

If the applicant chooses to use a plant-specific program that is not a GALL AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.3.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

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 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 3.0-1 of this SRP-LR provides 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-LR subsection.

3.3.3 Review Procedures

For each area of review, the following review procedures are to be followed.

3.3.3.1 AMR Results Consistent with the GALL Report

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to the GALL Report in its LRA. 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 applicant 

has stated that the applicable aging effects and industry and plant-specific operating experience 

have been reviewed by the applicant and are evaluated in the GALL Report. 

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL 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 Report as applicable to its plant. 

3.3.3.2 AMR Results Report for Which Further Evaluation is Recommended by the 

GALL 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 Report AMR item to which the 

LRA AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL 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.
NUREG-1800, Rev. 2 3.3-6 December 2010

3.3.3.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in 

Section 4.3 of this SRP-LR. 

3.3.3.2.2 Cracking due to Stress Corrosion Cracking and Cyclic Loading

The GALL Report also recommends further evaluation of programs to manage cracking due to 

SCC and cyclic loading in the stainless steel non-regenerative heat exchangers in the chemical 

and volume control system (PWR) exposed to treated borated water >60°C (>140°F). The water 

chemistry program relies on monitoring and control of water chemistry to manage the aging 

effects of cracking due to SCC and cyclic loading. The GALL 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 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.

3.3.3.2.3 Cracking due to Stress Corrosion Cracking

The GALL Report recommends further evaluation to manage cracking due to stress corrosion 

cracking of stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air environments containing sufficient halides (primarily chlorides) and in which 

condensation or deliquescence 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. 

The reviewer should determine whether an adequate program is used to manage the aging 

effect based on the applicable environmental conditions and ASME Code requirements. 

Cracking is only known to occur in environments containing sufficient halides (primarily 

chlorides) and in which condensation or deliquescence is possible. Condensation or 

deliquescence should generally be assumed to be possible. Applicable outdoor air 

environments (and associated indoor air environments) include, but are not limited to, those 

within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is 

treated with salt in the wintertime, those areas in which the soil contains more than trace 

chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine 

compounds, and those areas subject to chloride contamination from other agricultural or 

industrial sources. This item is applicable for the environments described above. GALL AMP 

XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the aging effect.

3.3.3.2.4 Loss of Material due to Cladding Breach 

The GALL Report recommends further evaluation of programs to manage loss of material due 

to cladding breach for PWR steel charging pump casings with stainless steel cladding. The 

GALL Report references NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump 

Casings Caused by Cladding Cracks and recommends further evaluation on a plant-specific 

basis to ensure that the aging effect is adequately managed. The reviewer reviews the 

applicant’s proposed programs on a case-by-case basis to ensure that an adequate program 

will be in place for the management of general corrosion of these components. 
December 2010 3.3-7 NUREG-1800, Rev 2

3.3.3.2.5 Loss of Material due to Pitting and Crevice Corrosion

The GALL Report recommends further evaluation to manage loss of material due to pitting and 

crevice corrosion of stainless steel piping, piping components, piping elements, and tanks 

exposed to outdoor air environments containing sufficient halides (primarily chlorides) and in 

which condensation or deliquescence is possible. The possibility of pitting and crevice corrosion 

also extends to components exposed to air which has recently been introduced into buildings, 

i.e., components near intake vents. The reviewer should determine whether an adequate 

program is used to manage the aging effect based on the applicable environmental conditions 

and ASME Code requirements. Pitting and crevice corrosion is only known to occur in 

environments containing sufficient halides (primarily chlorides) and in which condensation or 

deliquescence is possible. Condensation or deliquescence should generally be assumed to be 

possible. Applicable outdoor air environments (and associated indoor air environments) include, 

but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 

1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil 

contains more than trace chlorides, those plants having cooling towers where the water is 

treated with chlorine or chlorine compounds, and those areas subject to chloride contamination 

from other agricultural or industrial sources. This item is applicable for the environments 

described above. GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method 

to manage the aging effect.

3.3.3.2.6 Quality Assurance for Aging Management of Nonsafety-Related Components

The applicant’s aging management programs for license renewal 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 license renewal. 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.

3.3.3.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

The reviewer should confirm that the applicant, in its LRA, 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 Report or a plant-specific program. 

Review procedures are described in Branch Technical Position RSLB-1 (Appendix A.1 of this 

SRP-LR).

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA AMP with the exception will 
NUREG-1800, Rev. 2 3.3-8 December 2010

satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, not identified by 

the LRA, between the LRA AMP and the GALL Report AMP with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA 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 Report pertinent to the auxiliary systems 

components are summarized in Table 3.3-1 of this SRP-LR. The “Rev 2 Item” (for 2010) and 

“Rev1 Item” (for 2005 counterpart) columns identify the AMR item numbers in the GALL Report, 

Chapter VII, presenting detailed information summarized by this row.

3.3.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in its FSAR supplement information 

equivalent to that in Table 3.0-1 for aging management of the auxiliary systems. Table 3.3-2 

lists the AMPs that are applicable for this SRP-LR subsection. The reviewer also confirms that 

the applicant has provided information for subsection 3.3.3.3, “AMR Results Not Consistent with 

or Not Addressed in the GALL Report,” equivalent to that in Table 3.0-1.

The 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 and finds it acceptable 

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.

As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the LRA to any future aging management activities, including enhancements and commitments, 

to be completed before entering the period of extended operation. The 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 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 auxiliary 

systems components will be adequately managed so that the intended functions 

will be maintained consistent with the CLB for the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

The staff also reviewed the applicable 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).
December 2010 3.3-9 NUREG-1800, Rev 2

3.3.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.

3.3.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

3. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.

4. ASME Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components,” The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

5. ASTM D95-83, Standard Test Method for Water in Petroleum Products and Bituminous 

Materials by Distillation, American Society for Testing and Materials, West Conshohocken, 

PA, 1990.
NUREG-1800, Rev. 2 3.3-10 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

1 BWR/

PWR

Steel Cranes: 

structural girders 

exposed to Air –

indoor, uncontrolled 

(External)

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated 

for the period of extended 

operation for structural girders of 

cranes that fall within the scope 

of 10 CFR 54 (Standard Review 

Plan, Section 4.7, “Other PlantSpecific Time-Limited Aging 

Analyses,” for generic guidance 

for meeting the requirements of 

10 CFR 54.21(c)(1))

Yes, TLAA (See 

subsection 3.3.2.2.1

2 BWR/

PWR

Stainless steel, Steel 

Heat exchanger 

components and 

tubes, Piping, piping 

components, and 

piping elements 

exposed to Treated 

borated water, Air -

indoor, uncontrolled, 

Treated water

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated 

for the period of extended 

operation. See the SRP, Section 

4.3 “Metal Fatigue,” for 

acceptable methods for meeting 

the requirements of 10 CFR 

54.21(c)(1).

Yes, TLAA (See 

subsection 3.3.2.2.1

3 PWR Stainless steel Heat 

exchanger 

components, nonregenerative exposed 

to Treated borated 

water >60°C (>140°F)

Cracking 

due to stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M2, “Water 

Chemistry” 

The AMP is to be augmented by 

verifying the absence of cracking 

due to stress corrosion cracking 

and cyclic loading. An acceptable 

verification program is to include 

temperature and radioactivity 

monitoring of the shell side water, 

and eddy current testing of tubes.

Yes, plant-specific 

(See subsection 

3.3.2.2.2)

4 BWR/

PWR

Stainless steel Piping, 

piping components, 

Cracking 

due to stress 

Chapter XI.M36, "External 

Surfaces Monitoring of 

Yes, environmental 

conditions need to b
December 2010 3.3-11 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

and piping elements; 

tanks exposed to Air –

outdoor

corrosion cracking Mechanical Components" evaluated (See 

subsection 3.3.2.2.3

5 PWR Steel (with stainless 

steel or nickel-alloy 

cladding) Pump 

Casings exposed to 

Treated borated water

Loss of material

due to cladding 

breach

A plant-specific aging 

management program is to be 

evaluated. 

Reference NRC Information 

Notice 94-63, “Boric Acid 

Corrosion of Charging Pump 

Casings Caused by Cladding 

Cracks."

Yes, verify that plant

specific program 

addresses clad 

cracking (See 

subsection 3.3.2.2.4

6 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements; 

tanks exposed to Air –

outdoor

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

Yes, environmental 

conditions need to b

evaluated (See 

subsection 3.3.2.2.5

7 PWR Stainless steel Highpressure pump, 

casing exposed to 

Treated borated water

Cracking 

due to cyclic 

loading

Chapter XI.M1, "ASME Section XI 

Inservice Inspection, Subsections 

IWB, IWC, and IWD"

No 

8 PWR Stainless steel Heat 

exchanger 

Cracking 

due to cyclic 

Chapter XI.M1, "ASME Section XI 

Inservice Inspection, Subsections 

No 
NUREG-1800, Rev. 2 3.3-12 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

components and 

tubes exposed to 

Treated borated water 

>60°C (>140°F)

loading IWB, IWC, and IWD"

9 PWR Steel, Aluminum, 

Copper alloy (>15% 

Zn or >8% Al) External 

surfaces, Piping, 

piping components, 

and piping elements, 

Bolting exposed to Air 

with borated water 

leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No 

10 BWR/

PWR

Steel, high-strength 

Closure bolting 

exposed to Air with 

steam or water 

leakage

Cracking 

due to stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M18, "Bolting 

Integrity"

No 

11 BWR/

PWR

Steel, high-strength 

High-pressure pump, 

closure bolting 

exposed to Air with 

steam or water 

leakage

Cracking 

due to stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M18, "Bolting

Integrity"

No 

12 BWR/

PWR

Steel; stainless steel 

Closure bolting, 

Bolting exposed to 

Condensation, Air –

indoor, uncontrolled 

(External), Air –

outdoor (External)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting 

Integrity"

No 
December 2010 3.3-13 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

13 BWR/

PWR

Steel Closure bolting 

exposed to Air with 

steam or water 

leakage

Loss of material 

due to general 

corrosion

Chapter XI.M18, "Bolting 

Integrity"

No 

14 BWR/

PWR

Steel, Stainless Steel 

Bolting exposed to 

Soil

Loss of preload Chapter XI.M18, "Bolting 

Integrity"

No 

15 BWR/

PWR

Steel; stainless steel, 

Copper alloy, Nickel 

alloy, Stainless steel 

Closure bolting, 

Bolting exposed to Air 

– indoor, uncontrolled 

(External), Any 

environment, Air –

outdoor (External), 

Raw water, Treated 

borated water, Fuel 

oil, Treated water

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting 

Integrity"

No 

16 BWR Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Treated 

water >60°C (>140°F)

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M2, "Water 

Chemistry," and 

Chapter XI.M25, “BWR Reactor 

Water Cleanup System”

No 

17 BWR Stainless steel Heat 

exchanger tubes 

exposed to Treated 

water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection"

No 

18 BWR/

PWR

Stainless steel Highpressure pump, Cracking 

due to stress 

Chapter XI.M2, “Water 

Chemistry,” and 

No 
NUREG-1800, Rev. 2 3.3-14 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

casing, Piping, piping 

components, and 

piping elements 

exposed to Treated 

borated water >60°C 

(>140°F), Sodium 

pentaborate solution 

>60°C (>140°F)

corrosion cracking Chapter XI.M32, “One-Time 

Inspection”

19 BWR/

PWR

Stainless steel 

Regenerative heat 

exchanger 

components exposed 

to Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

20 BWR/

PWR

Stainless steel, 

Stainless steel; steel 

with stainless steel 

cladding Heat 

exchanger 

components exposed 

to Treated borated 

water >60°C (>140°F), 

Treated water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

21 BWR Steel Piping, piping 

components, and 

piping elements 

exposed to Treated 

water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

22 BWR Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Treated 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 
December 2010 3.3-15 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

water corrosion

23 BWR/

PWR

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Treated 

water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

24 BWR Aluminum Piping, 

piping components, 

and piping elements 

exposed to Treated 

water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

25 BWR Stainless steel, 

Stainless steel; steel 

with stainless steel 

cladding, Aluminum 

Piping, piping 

components, and 

piping elements, Heat 

exchanger 

components exposed 

to Treated water, 

Sodium pentaborate 

solution

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

26 BWR/

PWR

Steel (with elastomer 

lining), Steel (with 

elastomer lining or 

stainless steel 

cladding) Piping, 

piping components, 

and piping elements 

exposed to Treated 

water

Loss of material 

due to pitting and 

crevice corrosion 

(only for steel after 

lining/cladding 

degradation)

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 
NUREG-1800, Rev. 2 3.3-16 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

27 BWR Stainless steel Heat 

exchanger tubes 

exposed to Treated 

water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

28 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, and 

piping elements, 

Piping, piping 

components, and 

piping elements; tanks 

exposed Treated 

water >60°C (>140°F), 

Treated borated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water 

Chemistry”

No 

29 BWR/

PWR

Steel (with stainless 

steel cladding); 

stainless steel Piping, 

piping components, 

and piping elements 

exposed to Treated 

borated water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry”

No 

30 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

Changes in 

material properties 

due to aggressive 

chemical attack

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 
December 2010 3.3-17 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

Water

BWR/

PWR

Fiberglass, HDPE 

Piping, piping 

components, and 

piping elements 

exposed to Raw water 

(internal)

Cracking, 

blistering, change 

in color 

due to water 

absorption

Chapter XI.M20, "Open-Cycle 

Cooling Water System" 

No 

31 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

Water

Cracking 

due to settling

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

32 BWR/

PWR

Reinforced concrete, 

asbestos cement 

Piping, piping 

components, and 

piping elements 

exposed to Raw water

Cracking 

due to aggressive 

chemical attack 

and leaching;

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

BWR/

PWR

Elastomer seals and 

components exposed 

to raw water

Hardening and 

loss of strength 

due to elastomer 

degradation; loss 

of material due to 

erosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

33 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

Loss of material 

due to abrasion, 

cavitation, 

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 
NUREG-1800, Rev. 2 3.3-18 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

components, and 

piping elements 

exposed to Raw 

Water

aggressive 

chemical attack, 

and leaching

34 BWR/

PWR

Nickel alloy, Copper 

alloy Piping, piping 

components, and 

piping elements 

exposed to Raw water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

35 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

36 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

37 BWR/

PWR

Steel (with coating or 

lining) Piping, piping 

components, and 

piping elements 

exposed to Raw water

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 
December 2010 3.3-19 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

corrosion; 

lining/coating 

degradation

38 BWR/

PWR

Copper alloy, Steel 

Heat exchanger 

components exposed 

to Raw water

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

39 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

40 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to pitting and 

crevice corrosion; 

fouling that leads 

to corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

41 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 

42 BWR/

PWR

Copper alloy, 

Titanium, Stainless 

steel Heat exchanger 

tubes exposed to Raw 

water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-Cycle 

Cooling Water System"

No 
NUREG-1800, Rev. 2 3.3-20 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

43 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Closedcycle cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

44 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 stress 

corrosion cracking

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

45 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements; tanks

exposed to Closedcycle cooling water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

46 BWR/

PWR

Steel, Copper alloy 

Heat exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to Closedcycle cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 
December 2010 3.3-21 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

47 BWR Stainless steel; steel 

with stainless steel 

cladding Heat 

exchanger 

components exposed 

to Closed-cycle 

cooling water

Loss of material 

due to 

microbiologicallyinfluenced 

corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

48 BWR/

PWR

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Closedcycle cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

49 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Closedcycle cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 

50 BWR/

PWR

Stainless steel, 

Copper Alloy, Steel 

Heat exchanger tubes 

exposed to Closedcycle cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed 

Treated Water Systems"

No 
NUREG-1800, Rev. 2 3.3-22 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

51 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 

neutron-absorbing 

capacity 

due to boraflex 

degradation

Chapter XI.M22, “Boraflex 

Monitoring”

No 

52 BWR/

PWR

Steel Cranes: rails 

and structural girders 

exposed to Air –

indoor, uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M23, “Inspection of 

Overhead Heavy Load and Light 

Load (Related to Refueling) 

Handling Systems”

No 

53 BWR/

PWR

Steel Cranes - rails 

exposed to Air –

indoor, uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M23, “Inspection of 

Overhead Heavy Load and Light 

Load (Related to Refueling) 

Handling Systems”

No 

54 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to 

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M24, “Compressed 

Air Monitoring"

No 
December 2010 3.3-23 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

Condensation

55 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements: 

compressed air 

system exposed to 

Condensation 

(Internal)

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.M24, “Compressed 

Air Monitoring”

No 

56 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to 

Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M24, “Compressed 

Air Monitoring”

No 

57 BWR/

PWR

Elastomers Fire 

barrier penetration 

seals exposed to Air -

indoor, uncontrolled, 

Air – outdoor

Increased 

hardness; 

shrinkage; loss of 

strength 

due to weathering

Chapter XI.M26, "Fire Protection" No 

58 BWR/

PWR

Steel Halon/carbon 

dioxide fire 

suppression system 

piping, piping 

components, and 

piping elements 

exposed to Air –

indoor, uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M26, "Fire Protection" No 

59 BWR/

PWR

Steel Fire rated doors 

exposed to Air -

indoor, uncontrolled, 

Loss of material 

due to wear

Chapter XI.M26, "Fire Protection" No 
NUREG-1800, Rev. 2 3.3-24 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

Air – outdoor

60 BWR/

PWR

Reinforced concrete 

Structural fire barriers: 

walls, ceilings and 

floors exposed to Air -

indoor, uncontrolled

Concrete cracking 

and spalling 

due to aggressive 

chemical attack, 

and reaction with 

aggregates

Chapter XI.M26, “Fire Protection,” 

and 

Chapter XI.S6, “Structures 

Monitoring”

No 

61 BWR/

PWR

Reinforced concrete 

Structural fire barriers: 

walls, ceilings and 

floors exposed to Air –

outdoor

Cracking, loss of 

material 

due to freezethaw, aggressive 

chemical attack, 

and reaction with 

aggregates

Chapter XI.M26, “Fire Protection,” 

and 

Chapter XI.S6, “Structures 

Monitoring”

No 

62 BWR/

PWR

Reinforced concrete 

Structural fire barriers: 

walls, ceilings and 

floors exposed to Air -

indoor, uncontrolled, 

Air – outdoor

Loss of material 

due to corrosion of 

embedded steel

Chapter XI.M26, “Fire Protection,” 

and 

Chapter XI.S6, “Structures 

Monitoring”

No 

63 BWR/

PWR

Steel Fire Hydrants 

exposed to Air –

outdoor

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M27, "Fire Water 

System"

No 

64 BWR/

PWR

Steel, Copper alloy 

Piping, piping 

components, and 

piping elements 

exposed to Raw water

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

Chapter XI.M27, "Fire Water 

System"

No 
December 2010 3.3-25 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

that leads to 

corrosion

65 BWR/

PWR

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M27, "Fire Water 

System"

No 

66 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Raw water

Loss of material 

due to pitting and 

crevice corrosion; 

fouling that leads 

to corrosion

Chapter XI.M27, "Fire Water 

System"

No 

67 BWR/

PWR

Steel Tanks exposed 

to Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M29, “Aboveground 

Metallic Tanks”

No 

68 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements 

exposed to Fuel oil

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M30, "Fuel Oil 

Chemistry", and 

Chapter XI.M32, "One-Time 

Inspection" 

No 

69 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Fuel oil

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

70 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements; tanks 

exposed to Fuel oil

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 
NUREG-1800, Rev. 2 3.3-26 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

corrosion; fouling 

that leads to 

corrosion

71 BWR/

PWR

Stainless steel, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Fuel oil

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

No 

72 BWR/

PWR

Gray cast iron, Copper 

alloy (>15% Zn or 

>8% Al) Piping, piping 

components, and 

piping elements, Heat 

exchanger 

components exposed 

to Treated water, 

Closed-cycle cooling 

water, Soil, Raw water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

No 
December 2010 3.3-27 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

73 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

components, and 

piping elements 

exposed to Air -

outdoor

Changes in 

material properties 

due to aggressive 

chemical attack

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 
NUREG-1800, Rev. 2 3.3-28 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

74 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

components, and 

piping elements 

exposed to Air -

outdoor

Cracking 

due to settling

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

75 BWR/

PWR

Reinforced concrete, 

asbestos cement 

Piping, piping 

components, and 

piping elements 

exposed to Air –

outdoor

Cracking 

due to aggressive 

chemical attack 

and leaching; 

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

76 BWR/

PWR

Elastomers Elastomer: 

seals and components 

exposed to Air –

indoor, uncontrolled 

(Internal/External)

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

77 BWR/

PWR

Concrete; 

cementitious material 

Piping, piping 

components, and 

piping elements 

exposed to Air -

outdoor

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

78 BWR/

PWR

Steel Piping and 

components (External 

surfaces), Ducting and 

components (External 

surfaces), Ducting; 

closure bolting 

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 
December 2010 3.3-29 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

exposed to Air –

indoor, uncontrolled 

(External), Air –

indoor, uncontrolled 

(External), Air –

outdoor (External), 

Condensation 

(External)

79 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to 

Condensation 

(External)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

80 BWR/

PWR

Steel Heat exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External), Air –

outdoor (External)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

81 BWR/

PWR

Copper alloy, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (External), Air 

- outdoor

Loss of material 

due to pitting and

crevice corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of 

Mechanical Components"

No 

82 BWR/

PWR

Elastomers Elastomer: 

seals and components 

Loss of material 

due to wear

Chapter XI.M36, "External 

Surfaces Monitoring of 

No 
NUREG-1800, Rev. 2 3.3-30 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

exposed to Air –

indoor, uncontrolled 

(External)

Mechanical Components" 

83 BWR/

PWR

Stainless steel Diesel 

engine exhaust piping, 

piping components, 

and piping elements 

exposed to Diesel 

exhaust

Cracking 

due to stress 

corrosion cracking

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

85 BWR/

PWR

Elastomers Elastomer 

seals and components 

exposed to Closedcycle cooling water

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

86 BWR/

PWR

Elastomers 

Elastomers, linings, 

Elastomer: seals and 

components exposed 

to Treated borated 

water, Treated water, 

Raw water

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

88 BWR/

PWR

Steel; stainless steel 

Piping, piping 

components, and 

piping elements, 

Piping, piping 

components, and 

piping elements, 

diesel engine exhaust

exposed to Raw water 

(potable), Diesel 

exhaust

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 
December 2010 3.3-31 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

89 BWR/

PWR

Steel, Copper alloy 

Piping, piping 

components, and 

piping elements 

exposed to Moist air 

or condensation 

(Internal)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

90 BWR/

PWR

Steel Ducting and 

components (Internal 

surfaces) exposed to 

Condensation 

(Internal)

Loss of material 

due to general, 

pitting, crevice, 

and (for drip pans 

and drain lines) 

microbiologicallyinfluenced 

corrosion 

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

91 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements; tanks 

exposed to Waste 

Water

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

92 BWR/

PWR

Aluminum Piping, 

piping components, 

and piping elements 

exposed to 

Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

93 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Raw water 

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 
NUREG-1800, Rev. 2 3.3-32 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

(potable)

94 BWR/

PWR

Stainless steel 

Ducting and 

components exposed 

to Condensation

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

95 BWR/

PWR

Copper alloy, 

Stainless steel, Nickel 

alloy, Steel Piping, 

piping components, 

and piping elements, 

Heat exchanger 

components, Piping, 

piping components, 

and piping elements; 

tanks exposed to 

Waste water, 

Condensation 

(Internal)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

96 BWR/

PWR

Elastomers Elastomer: 

seals and components 

exposed to Air –

indoor, uncontrolled 

(Internal)

Loss of material 

due to wear

Chapter XI.M38, "Inspection of 

Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components"

No 

97 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements, 

Reactor coolant pump 

oil collection system: 

tanks, Reactor coolant 

pump oil collection 

system: piping, tubing, 

valve bodies exposed 

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

No 
December 2010 3.3-33 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

to Lubricating oil 

98 BWR/

PWR

Steel Heat exchanger 

components exposed 

to Lubricating oil

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

No 

99 BWR/

PWR

Copper alloy, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Lubricating 

oil

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

No 

100 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Lubricating 

oil

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

No 
NUREG-1800, Rev. 2 3.3-34 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

101 BWR/

PWR

Aluminum Heat 

exchanger tubes 

exposed to Lubricating 

oil

Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricating Oil 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

No 

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 

neutron-absorbing 

capacity; change 

in dimensions and 

loss of material 

due to effects of 

SFP environment

Chapter XI.M40, "Monitoring of 

Neutron-Absorbing Materials 

other than Boraflex"

No 

103 BWR/

PWR

Reinforced concrete, 

asbestos cement 

Piping, piping 

components, and 

piping elements 

exposed to Soil or 

concrete

Cracking 

due to aggressive 

chemical attack 

and leaching; 

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

104 BWR/

PWR

HDPE, Fiberglass 

Piping, piping 

components, and 

Cracking, 

blistering, change 

in color 

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 
December 2010 3.3-35 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

piping elements 

exposed to Soil or 

concrete

due to water 

absorption

105 BWR/

PWR

Concrete cylinder 

piping, Asbestos 

cement pipe Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete

Cracking, spalling, 

corrosion of rebar 

due to exposure of 

rebar

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

106 BWR/

PWR

Steel (with coating or 

wrapping) Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

107 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

108 BWR/

PWR

Titanium, Super 

austenitic, Aluminum, 

Copper Alloy, 

Stainless Steel Piping, 

piping components, 

and piping elements, 

Bolting exposed to 

Soil or concrete

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 
NUREG-1800, Rev. 2 3.3-36 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

109 BWR/

PWR

Steel Bolting exposed 

to Soil or concrete

Loss of material

due to general, 

pitting and crevice 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

BWR/

PWR

Underground 

Aluminum, Copper 

Alloy, Stainless Steel 

and Steel Piping, 

piping components, 

and piping elements

Loss of material 

due to general 

(steel only), pitting 

and crevice 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

No 

110 BWR Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Treated 

water >60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and 

Chapter XI.M2, “Water 

Chemistry” 

No 

111 BWR/

PWR

Steel Structural steel 

exposed to Air –

indoor, uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

No 

112 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements 

exposed to Concrete

None None, provided 

1) attributes of the concrete are 

consistent with ACI 318 or ACI 

349 (low water-to-cement ratio, 

low permeability, and adequate 

air entrainment) as cited in 

NUREG-1557, and 

2) plant OE indicates no 

degradation of the concrete

No, if conditions are 

met.

113 BWR/

PWR

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air – dry 

None None NA - No AEM or AM
December 2010 3.3-37 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

(Internal/External), Air 

– indoor, uncontrolled 

(Internal/External), Air 

– indoor, controlled 

(External), Gas

114 BWR/

PWR

Copper alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(Internal/External), Air 

– dry, Gas

None None NA - No AEM or AM

115 PWR Copper alloy (≤15% 

Zn and ≤8% Al) 

Piping, piping 

components, and 

piping elements 

exposed to Air with 

borated water leakage

None None NA - No AEM or AM

116 BWR/

PWR

Galvanized steel 

Piping, piping 

components, and 

piping elements 

exposed to Air -

indoor, uncontrolled

None None NA - No AEM or AM

117 BWR/

PWR

Glass Piping elements 

exposed to Air –

indoor, uncontrolled 

(External), Lubricating 

oil, Closed-cycle 

cooling water, Air –

outdoor, Fuel oil, Raw 

water, Treated water, 

None None NA - No AEM or AM
NUREG-1800, Rev. 2 3.3-38 December 201

0

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

Treated borated 

water, Air with borated 

water leakage, 

Condensation 

(Internal/External) Gas

118 BWR/

PWR

Nickel alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External)

None None NA - No AEM or AM

119 BWR/

PWR

Nickel alloy, PVC, 

Glass Piping, piping 

components, and 

piping elements 

exposed to Air with 

borated water 

leakage, Air – indoor, 

uncontrolled, 

Condensation 

(Internal), Waste 

Water

None None NA - No AEM or AM

120 BWR/

PWR

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(Internal/External), Air 

– indoor, uncontrolled 

(External), Air with 

borated water 

leakage, Concrete, Air 

– dry, Gas

None None NA - No AEM or AM
December 2010 3.3-39 NUREG-1800, Rev. 2

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

ID Type Component Aging Effect/ 

Mechanism

Aging Management Programs Further Evaluation 

Recommended

121 BWR/

PWR

Steel Piping, piping 

components, and 

piping elements 

exposed to Air –

indoor, controlled 

(External), Air – dry, 

Gas

None None NA - No AEM or AM

122 BWR/

PWR

Titanium Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled or 

Air – outdoor

None None NA - No AEM or AM

123 BWR/

PWR

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains > 5% 

aluminum or more 

than 0.20% oxygen or 

any amount of tin) 

Heat exchanger 

components other 

than tubes, Piping, 

piping components, 

and piping elements 

exposed to Raw water

None None NA - No AEM or AM
NUREG-1800, Rev. 2 3.3-40 December 2010

Table 3.3-2 Aging Management Programs Recommended for Aging Management of 

Auxiliary Systems 

GALL Report Chapter/AMP Program Name

Chapter XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD

Chapter XI.M2 Water Chemistry

Chapter XI.M7 BWR Stress Corrosion Cracking

Chapter XI.M10 Boric Acid Corrosion

Chapter XI.M18 Bolting Integrity 

Chapter XI.M20 Open-Cycle Cooling Water System 

Chapter XI.M21A Closed Treated Water Systems

Chapter XI.M22 Boraflex Monitoring

Chapter XI.M23 Inspection of Overhead Heavy and Light Loads (Related to 

Refueling) Handling Systems

Chapter XI.M24 Compressed Air Monitoring

Chapter XI.M25 BWR Reactor Cleanup System

Chapter XI.M26 Fire Protection

Chapter XI.M27 Fire Water System

Chapter XI.M29 Aboveground Metallic Tanks

Chapter XI.M30 Fuel Oil Chemistry

Chapter XI.M32 One-Time Inspection

Chapter XI.M33 Selective Leaching

Chapter XI.M36 External Surfaces Monitoring of Mechanical Components

Chapter XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components

Chapter XI.M39 Lubricating Oil Analysis

Chapter XI.M40 Monitoring of Neutron-Absorbing Materials Other than Boraflex

Chapter XI.M41 Buried and Underground Piping and Tanks

Chapter XI.S6 Structures Monitoring

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP
December 2010 3.4-1 NUREG-1800, Rev. 2

3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM

Review Responsibilities

Primary - Branch assigned responsibility by PM as described in Section 3.0 of this SRP-LR.

3.4.1 Areas of Review

This section addresses the aging management review (AMR) and the associated aging 

management program (AMP) 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 FSAR, consistent with the “Standard 

Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants” (NUREG0800). 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 license renewal 

are steam turbine, main steam, extraction steam, feedwater, condensate, steam generator 

blowdown, and auxiliary feedwater. This review plan section also includes structures and 

components in nonsafety-related systems that are not connected to safety-related 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-LR. The aging management for portions of the 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-LR. 

The responsible review organization is to review the following LRA AMR and AMP items 

assigned to it, per SRP-LR Section 3.0:

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL Report AMPs 

• Plant-specific AMPs

FSAR Supplement

• The responsible review organization is to review the FSAR Supplement associated with 

each assigned AMP.
NUREG-1800, Rev. 2 3.4-2 December 2010

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 NRC’s regulations in 10 CFR 54.21.

3.4.2.1 AMR Results Consistent with the GALL Report 

The AMR and the AMPs applicable to the steam and power conversion system are described 

and evaluated in Chapter VIII of NUREG-1801 (GALL Report).

The applicant’s LRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific LRA AMR item and the associated LRA AMP are consistent with the 

cited GALL Report AMR item. The reviewer should then confirm that the LRA AMR item is 

consistent with the GALL Report AMR item to which it is compared.

When the applicant is crediting a different aging management program than recommended in 

the GALL Report, the reviewer should confirm that the alternate aging management program is 

valid to use for aging management and will be capable of managing the effects of aging as 

adequately as the aging management program recommended by the GALL Report.

3.4.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item

to which the LRA AMR item is compared identifies that “further evaluation is recommended,”

then additional criteria apply as identified by the GALL Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.4-1, comparing the “Further Evaluation 

Recommended” and the “Rev2 Item” columns, for the AMR items that reference the following 

subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.4.2.2.1 Cumulative Fatigue Damage 

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). This TLAA is addressed separately in Section 4.3, “Metal 

Fatigue Analysis,” of this SRP-LR. The related GALL Report items invoked by the subsection 

are VIII.D1.S-11, VIII.D2.S-11, VIII.G.S-11, VIII.B1.S-08, VIII.B2.S-08.

3.4.2.2.2 Cracking due to Stress Corrosion Cracking (SCC)

Cracking due to stress corrosion cracking could occur for stainless steel piping, piping 

components, piping elements, and tanks exposed to outdoor air. The possibility of cracking also 

extends to components exposed to air which has recently been introduced into buildings, i.e., 

components near intake vents. Cracking is only known to occur in environments containing 

sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible. 

Condensation or deliquescence should generally be assumed to be possible. Applicable 

outdoor air environments (and associated indoor air environments) include, but are not limited 

to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a 

highway which is treated with salt in the wintertime, those areas in which the soil contains more 

than trace chlorides, those plants having cooling towers where the water is treated with chlorine 
December 2010 3.4-3 NUREG-1800, Rev. 2

or chlorine compounds, and those areas subject to chloride contamination from other 

agricultural or industrial sources. This item is applicable for the environments described above. 

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the 

aging effect. The applicant may demonstrate that this item is not applicable by describing the 

outdoor air environment present at the plant and demonstrating that external chloride stress 

corrosion cracking is not expected. The GALL Report recommends further evaluation to 

determine whether an adequate aging management program is used to manage this aging 

effect based on the environmental conditions applicable to the plant and ASME Code Section XI 

requirements applicable to the components.

3.4.2.2.3 Loss of Material due to Pitting and Crevice Corrosion 

Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, piping 

components, piping elements, and tanks exposed to outdoor air. The possibility of pitting and 

crevice corrosion also extends to components exposed to air which has recently been 

introduced into buildings, i.e., components near intake vents. Pitting and crevice corrosion is 

only known to occur in environments containing sufficient halides (primarily chlorides) and in 

which condensation or deliquescence is possible. Condensation or deliquescence should 

generally be assumed to be possible. Applicable outdoor air environments (and associated 

indoor air environments) include, but are not limited to, those within approximately 5 miles of a 

saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the 

wintertime, those areas in which the soil contains more than trace chlorides, those plants having 

cooling towers where the water is treated with chlorine or chlorine compounds, and those areas 

subject to chloride contamination from other agricultural or industrial sources. This item is 

applicable for the environments described above.

GALL AMP XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the 

aging effect. The applicant may demonstrate that this item is not applicable by describing the 

outdoor air environment present at the plant and demonstrating that external pitting or crevice 

corrosion is not expected. The GALL Report recommends further evaluation to determine 

whether an adequate aging management program is used to manage this aging effect based on 

the environmental conditions applicable to the plant and ASME Code Section XI requirements 

Quality Assurance for Aging Management of Nonsafety-Related Components.

3.4.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2, of this 

SRP-LR).

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

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 Report, the NRC reviewer performs an audit of aging 

management programs credited in the LRA to confirm consistency with the GALL AMPs 

identified in the GALL Report, Chapters X and XI.
NUREG-1800, Rev. 2 3.4-4 December 2010

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP with all 

exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, the 

reviewer identifies a difference between the LRA AMP and the GALL Report AMP that should 

have been identified as an exception to the GALL Report AMP, the difference should be 

reviewed and properly dispositioned. The reviewer should document the disposition of all LRAdefined exceptions and staff-identified differences.

The LRA should identify any enhancements that are needed to permit an existing LRA AMP to 

be declared consistent with the GALL Report AMP to which the LRA AMP is compared. The 

reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

LRA AMP to be consistent with the GALL Report AMP and also that the applicant has a 

commitment in the FSAR Supplement to implement the enhancement prior to the 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 AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.4.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

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 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 3.0-1 of this SRP-LR provides 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-LR 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 AMR Results Consistent with the GALL Report

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to the GALL Report in its LRA. 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 applicant 

has stated that the applicable aging effects and industry and plant-specific operating experience 

have been reviewed by the applicant and are evaluated in the GALL Report.

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL Report. Performance of this review requires 
December 2010 3.4-5 NUREG-1800, Rev. 2

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 Report as applicable to 

its plant.

3.4.3.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to which the 

LRA AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL Report for each of the following aging effect/aging 

mechanism combinations. Refer to Table 3.4-1 for the Rev 2 item references for the following 

subsections.

3.4.3.2.1 Cumulative Fatigue Damage 

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). The reviewer reviews the evaluation of this TLAA separately 

following the guidance in Section 4.3 of this SRP-LR.

3.4.3.2.2 Cracking due to Stress Corrosion Cracking 

The GALL Report recommends further evaluation to manage cracking due to stress corrosion 

cracking of stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air environments containing sufficient halides (primarily chlorides) and in which 

condensation or deliquescence 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.

The reviewer should determine whether an adequate program is used to manage the aging 

effect based on the applicable environmental conditions and ASME Code requirements. 

Cracking is only known to occur in environments containing sufficient halides (primarily 

chlorides) and in which condensation or deliquescence is possible. Condensation or 

deliquescence should generally be assumed to be possible. Applicable outdoor air 

environments (and associated indoor air environments) include, but are not limited to, those 

within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is 

treated with salt in the wintertime, those areas in which the soil contains more than trace 

chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine 

compounds, and those areas subject to chloride contamination from other agricultural or 

industrial sources. This item is applicable for the environments described above. GALL AMP 

XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the aging effect.

3.4.3.2.3 Loss of Material due to Pitting and Crevice Corrosion

The GALL Report recommends further evaluation to manage loss of material due to pitting and 

crevice corrosion of stainless steel piping, piping components, piping elements, and tanks 

exposed to outdoor air environments containing sufficient halides (primarily chlorides) and in 

which condensation or deliquescence is possible. The possibility of pitting and crevice corrosion 

also extends to components exposed to air which has recently been introduced into buildings, 

i.e., components near intake vents.
NUREG-1800, Rev. 2 3.4-6 December 2010

The reviewer should determine whether an adequate program is used to manage the aging 

effect based on the applicable environmental conditions and ASME Code requirements. Pitting 

and crevice corrosion is only known to occur in environments containing sufficient halides 

(primarily chlorides) and in which condensation or deliquescence is possible. Condensation or 

deliquescence should generally be assumed to be possible. Applicable outdoor air 

environments (and associated indoor air environments) include, but are not limited to, those 

within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is 

treated with salt in the wintertime, those areas in which the soil contains more than trace 

chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine 

compounds, and those areas subject to chloride contamination from other agricultural or 

industrial sources. This item is applicable for the environments described above. GALL AMP 

XI.M36, “External Surfaces Monitoring,” is an acceptable method to manage the aging effect.

3.4.3.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

The applicant’s aging management programs for license renewal 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 aging management review for license renewal. 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 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.

3.4.3.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

The reviewer should confirm that the applicant, in its LRA, 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 Report or a plant-specific program. 

Review procedures are described in Branch Technical Position RSLB-1 (Appendix A.1 of this 

SRP-LR).

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA 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 LRA, between the LRA AMP and the GALL Report AMP with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA 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 Report pertinent to the steam and power 

conversion system are summarized in Table 3.4-1 of this SRP-LR. The “Rev 2 Item” (for 2010) 

and “Rev1 Item” (for 2005 counterpart) columns identify the AMR item numbers in the GALL 

Report, Chapter VIII, presenting detailed information summarized by this row.
December 2010 3.4-7 NUREG-1800, Rev. 2

Table 3.4-1 of this SRP-LR may identify a plant-specific aging management program. If the 

applicant chooses to use a plant-specific program that is not a GALL AMP, the NRC reviewer 

should confirm that the plant-specific program satisfies the criteria of Branch Technical Position 

RLSB-1 (Appendix A.1.2.3 of this SRP-LR). 

3.4.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in the FSAR supplement information 

equivalent to that in Table 3.0-1 for aging management of the steam and power conversion 

systems. Table 3.4-2 lists the AMPs that are applicable for this SRP-LR subsection. The 

reviewer also confirms that the applicant has provided information for Subsection 3.4.3.3, “AMR 

Results Not Consistent with or Not Addressed in the GALL Report,” equivalent to that in Table 

3.0-1.

The 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 and finds it acceptable 

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.

As noted in Table 3.0-1, the applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the LRA to any future aging management activities, including enhancements and commitments, 

to be completed before entering the period of extended operation. The 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.

3.4.4 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 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 steam and 

power conversion system components will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

The staff also reviewed the applicable 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 in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.
NUREG-1800, Rev. 2 3.4-8 December 2010

3.4.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

3. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.
December 2010 3.4-9 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

1 BWR/PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Steam or Treated water

Cumulative fatigue damage 

due to fatigue

Fatigue is a timelimited aging analysis 

(TLAA) to be evaluated 

for the period of 

extended operation. 

See the SRP, Section 

4.3 “Metal Fatigue,” for 

acceptable methods for 

meeting the 

requirements of 10 CFR 

54.21(c)(1).

Yes, TLAA (See 

subsection 3.4.2.2.1)

2 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements; tanks 

exposed to Air –

outdoor

Cracking 

due to stress corrosion 

cracking

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components"

Yes, environmental 

conditions need to be 

evaluated (See 

subsection 3.4.2.2.2)

3 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements; tanks 

exposed to Air –

outdoor

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components"

Yes, environmental 

conditions need to be 

evaluated (See 

subsection 3.4.2.2.3)

4 PWR Steel External surfaces, 

Bolting exposed to Air 

with borated water 

leakage

Loss of material 

due to boric acid corrosion

Chapter XI.M10, “Boric 

Acid Corrosion”

No 
NUREG-1800, Rev. 2 3.4-10 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

5 BWR/PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Steam, Treated water

Wall thinning 

due to flow-accelerated 

corrosion

Chapter XI.M17, “FlowAccelerated Corrosion”No 

6 BWR/PWR Steel, Stainless Steel 

Bolting exposed to Soil

Loss of preload Chapter XI.M18, 

"Bolting Integrity "

No 

7 BWR/PWR High-strength steel 

Closure bolting 

exposed to Air with 

steam or water leakage

Cracking 

due to cyclic loading, stress 

corrosion cracking

Chapter XI.M18, 

"Bolting Integrity"

No 

8 BWR/PWR Steel; stainless steel 

Bolting, Closure bolting 

exposed to Air –

outdoor (External), Air –

indoor, uncontrolled 

(External)

Loss of material 

due to general (steel only), 

pitting, and crevice 

corrosion

Chapter XI.M18, 

"Bolting Integrity"

No 

9 BWR/PWR Steel Closure bolting 

exposed to Air with 

steam or water leakage

Loss of material 

due to general corrosion

Chapter XI.M18, 

"Bolting Integrity"

No 
December 2010 3.4-11 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

10 BWR/PWR Copper alloy, Nickel 

alloy, Steel; stainless 

steel, Steel; stainless 

steel Bolting, Closure 

bolting exposed to Any 

environment, Air –

outdoor (External), Air –

indoor, uncontrolled 

(External)

Loss of preload 

due to thermal effects, 

gasket creep, and selfloosening

Chapter XI.M18, 

"Bolting Integrity"

No 

11 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements, Tanks, 

Heat exchanger 

components exposed to 

Steam, Treated water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

12 BWR/PWR Steel; stainless steel 

Tanks exposed to 

Treated water

Loss of material 

due to general (steel only), 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

13 PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Treated water

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 
NUREG-1800, Rev. 2 3.4-12 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

14 BWR/PWR Steel Piping, piping 

components, and piping 

elements, PWR heat 

exchanger components 

exposed to Steam, 

Treated water

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

15 BWR/PWR Steel Heat exchanger 

components exposed to 

Treated water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

16 BWR/PWR Copper alloy, Stainless 

steel, Nickel alloy, 

Aluminum Piping, 

piping components, and 

piping elements, Heat 

exchanger components 

and tubes, PWR heat 

exchanger components 

exposed to Treated 

water, Steam

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 
December 2010 3.4-13 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

17 PWR Copper alloy Heat 

exchanger tubes 

exposed to Treated 

water

Reduction of heat transfer 

due to fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

18 BWR/PWR Copper alloy, Stainless 

steel Heat exchanger 

tubes exposed to 

Treated water

Reduction of heat transfer 

due to fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, “OneTime Inspection”

No 

19 BWR/PWR Stainless steel, Steel 

Heat exchanger 

components exposed to 

Raw water

Loss of material 

due to general, pitting, 

crevice, galvanic, and 

microbiologically-influenced 

corrosion; fouling that leads 

to corrosion

Chapter XI.M20, 

"Open-Cycle Cooling 

Water System"

No 

20 BWR/PWR Copper alloy, Stainless 

steel Piping, piping 

components, and piping 

elements exposed to 

Raw water

Loss of material 

due to pitting, crevice, and 

microbiologically-influenced 

corrosion

Chapter XI.M20, 

"Open-Cycle Cooling 

Water System"

No 

21 PWR Stainless steel Heat 

exchanger components 

exposed to Raw water

Loss of material 

due to pitting, crevice, and 

microbiologically-influenced 

corrosion; fouling that leads 

to corrosion

Chapter XI.M20, 

"Open-Cycle Cooling 

Water System"

No 

22 BWR/PWR Stainless steel, Copper 

alloy, Steel Heat 

exchanger tubes, Heat 

exchanger components 

exposed to Raw water

Reduction of heat transfer 

due to fouling

Chapter XI.M20, 

"Open-Cycle Cooling 

Water System"

No 
NUREG-1800, Rev. 2 3.4-14 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

23 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements 

exposed to Closedcycle cooling water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

24 BWR/PWR Steel Heat exchanger 

components exposed to 

Closed-cycle cooling 

water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

25 BWR/PWR Steel Heat exchanger 

components exposed to 

Closed-cycle cooling 

water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

26 BWR/PWR Stainless steel Heat 

exchanger 

components, Piping, 

piping components, and 

piping elements 

exposed to Closedcycle cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

27 BWR/PWR Copper alloy Piping, 

piping components, and 

piping elements 

exposed to Closedcycle cooling water

Loss of material 

due to pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 
December 2010 3.4-15 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

28 BWR/PWR Steel, Stainless steel, 

Copper alloy Heat 

exchanger components 

and tubes, Heat 

exchanger tubes 

exposed to Closedcycle cooling water

Reduction of heat transfer 

due to fouling

Chapter XI.M21A, 

"Closed Treated Water 

Systems"

No 

29 BWR/PWR Steel Tanks exposed to 

Air – outdoor (External)

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No 

30 BWR/PWR Steel, Stainless Steel, 

Aluminum Tanks 

exposed to Soil or 

Concrete, Air – outdoor 

(External)

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No 

31 BWR/PWR Stainless steel, 

Aluminum Tanks 

exposed to Soil or 

Concrete

Loss of material 

due to pitting, and crevice 

corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No 

32 BWR/PWR Gray cast iron Piping, 

piping components, and 

piping elements 

exposed to Soil

Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leaching”

No 
NUREG-1800, Rev. 2 3.4-16 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

33 BWR/PWR Gray cast iron, Copper 

alloy (>15% Zn or >8% 

Al) Piping, piping 

components, and piping 

elements exposed to 

Treated water, Raw 

water, Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leaching”

No 

34 BWR/PWR Steel External surfaces 

exposed to Air – indoor, 

uncontrolled (External), 

Air – outdoor (External), 

Condensation 

(External)

Loss of material 

due to general corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components"

No 

35 BWR/PWR Aluminum Piping, 

piping components, and 

piping elements 

exposed to Air -

outdoor

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components"

No 

36 PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Air – outdoor (Internal)

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 
December 2010 3.4-17 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

37 PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Condensation (Internal)

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

38 PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Raw water 

Loss of material 

due to general, pitting, 

crevice, galvanic, and 

microbiologically-influenced 

corrosion; fouling that leads 

to corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

39 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements 

exposed to 

Condensation (Internal)

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No 

40 BWR/PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Lubricating oil

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection” 

No 

41 PWR Steel Heat exchanger 

components exposed to 

Lubricating oil

Loss of material 

due to general, pitting, 

crevice, and 

microbiologically-influenced 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection” 

No 
NUREG-1800, Rev. 2 3.4-18 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

42 PWR Aluminum Piping, 

piping components, and 

piping elements 

exposed to Lubricating 

oil

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection”

No 

43 BWR/PWR Copper alloy Piping, 

piping components, and 

piping elements 

exposed to Lubricating 

oil

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection” 

No 

44 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements, Heat 

exchanger components 

exposed to Lubricating 

oil

Loss of material 

due to pitting, crevice, and 

microbiologically-influenced 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection” 

No 

45 PWR Aluminum Heat 

exchanger components 

and tubes exposed to 

Lubricating oil

Reduction of heat transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection”

No 

46 PWR Stainless steel, Steel, 

Copper alloy Heat 

exchanger tubes 

exposed to Lubricating 

oil

Reduction of heat transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, “OneTime Inspection” 

No 

47 BWR/PWR Steel (with coating or 

wrapping) Piping, 

piping components, and 

piping elements; tanks 

exposed to Soil or 

Concrete

Loss of material 

due to general, pitting, 

crevice, and 

microbiologically-influenced 

corrosion

Chapter XI.M41, 

"Buried and 

Underground Piping 

and Tanks"

No 
December 2010 3.4-19 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

48 BWR/PWR Stainless Steel Bolting 

exposed to Soil 

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M41, 

"Buried and 

Underground Piping 

and Tanks"

No 

49 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements 

exposed to Soil or 

Concrete

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M41, 

"Buried and 

Underground Piping 

and Tanks"

No 

50 BWR/PWR Steel Bolting exposed 

to Soil 

Loss of material

due to general, pitting and 

crevice corrosion

Chapter XI.M41, 

"Buried and 

Underground Piping 

and Tanks"

No 

BWR/PWR Underground Stainless 

Steel and Steel Piping, 

piping components, and 

piping elements

Loss of material 

due to general (steel only), 

pitting and crevice 

corrosion

Chapter XI.M41, 

"Buried and 

Underground Piping 

and Tanks"

No 

51 BWR/PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Concrete

None None, provided 

1) attributes of the 

concrete are consistent 

with ACI 318 or ACI 349 

(low water-to-cement 

ratio, low permeability, 

and adequate air 

entrainment) as cited in 

NUREG-1557, and 

2) plant OE indicates 

no degradation of the 

concrete

No, if conditions are

met.
NUREG-1800, Rev. 2 3.4-20 December 2010

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

52 BWR/PWR Aluminum Piping, 

piping components, and 

piping elements 

exposed to Gas, Air –

indoor, uncontrolled 

(Internal/External)

None None NA - No AEM or AMP 

53 PWR Copper alloy (≤15% Zn 

and ≤8% Al) Piping, 

piping components, and 

piping elements 

exposed to Air with 

borated water leakage

None None NA - No AEM or AMP 

54 BWR/PWR Copper alloy Piping, 

piping components, and 

piping elements 

exposed to Gas, Air –

indoor, uncontrolled 

(External)

None None NA - No AEM or AMP 

55 BWR/PWR Glass Piping elements 

exposed to Lubricating 

oil, Air – outdoor, 

Condensation 

(Internal/External), Raw 

water, Treated water, 

Air with borated water 

leakage, Gas, Closedcycle cooling water, Air 

– indoor, uncontrolled 

(External)

None None NA - No AEM or AMP 
December 2010 3.4-21 NUREG-1800, Rev. 2

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

GALL Report 

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

56 BWR/PWR Nickel alloy Piping, 

piping components, and 

piping elements 

exposed to Air – indoor, 

uncontrolled (External)

None None NA - No AEM or AMP 

57 BWR/PWR Nickel alloy, PVC 

Piping, piping 

components, and piping 

elements exposed to 

Air with borated water 

leakage, Air – indoor, 

uncontrolled, 

Condensation (Internal)

None None NA - No AEM or AMP 

58 BWR/PWR Stainless steel Piping, 

piping components, and 

piping elements 

exposed to Air – indoor, 

uncontrolled (External), 

Concrete, Gas, Air –

indoor, uncontrolled 

(Internal)

None None NA - No AEM or AMP 

59 BWR/PWR Steel Piping, piping 

components, and piping 

elements exposed to 

Air – indoor controlled 

(External), Gas

None None NA - No AEM or AMP 
NUREG-1800, Rev. 2 3.4-22 December 2010 

Table 3.4-2 Aging Management Programs Recommended for Aging 

Management of Steam and Power Conversion System 

GALL Report Chapter/AMP Program Name 

Chapter XI.M2 Water Chemistry 

Chapter XI.M10 Boric Acid Corrosion 

Chapter XI.M17 Flow-Accelerated Corrosion 

Chapter XI.M18 Bolting Integrity 

Chapter XI.M20 Open-Cycle Cooling Water System 

Chapter XI.M21A Closed Treated Water Systems 

Chapter XI.M29 Aboveground Metallic Tanks 

Chapter XI.M32 One-Time Inspection 

Chapter XI.M33 Selective Leaching 

Chapter XI.M36 External Surfaces Monitoring of Mechanical 

Components 

Chapter XI.M38 Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components 

Chapter XI.M39 Lubricating Oil Analysis 

Chapter XI.M41 Buried and Underground Piping and Tanks 

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP 
December 2010 3.5-1 NUREG-1800, Rev. 2

3.5 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES, AND COMPONENT 

SUPPORTS

Review Responsibilities

Primary - Branch assigned responsibility by PM as described in SRP-LR Section 3.0.

3.5.1 Areas of Review

This section addresses the aging management review (AMR) and the associated aging 

management program (AMP) for containments, structures, and component supports. For a 

recent vintage plant, the information related to containments, structures, and component 

supports is contained in Chapter 3, “Design of Structures, Components, Equipment, and 

Systems,” of the plant’s 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 PWR and BWR containment structures, 

safety-related and other structures, and component supports. 

The PWR containment structures consist of concrete (reinforced or prestressed) and steel 

containments. The BWR containment structures consist of Mark I, Mark II, and Mark III steel 

and concrete (reinforced or pre-stressed) 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 pump 

house, utility/piping tunnels, security lighting poles, manholes, duct banks), 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 ASME 

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, 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., 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 license renewal application (LRA) 

AMR and AMP items assigned to it, per SRP-LR section 3.0, for review:

AMRs

• AMR results consistent with the GALL Report 

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results that are not consistent with or not addressed in the GALL Report
NUREG-1800, Rev. 2 3.5-2 December 2010

AMPs

• Consistent with GALL 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 NRC’s regulations in 10 CFR 54.21.

3.5.2.1 AMR Results Consistent with the GALL Report 

The AMRs and the AMPs applicable to structures and component supports are described and 

evaluated in Chapters II and III of the NUREG-1801, (GALL Report). 

The applicant’s LRA should provide sufficient information so that the reviewer is able to confirm 

that the specific LRA AMR item and the associated LRA AMP are consistent with the cited 

GALL Report AMR item. The staff reviewer should then confirm that the LRA AMR item is 

consistent with the GALL Report AMR item to which it is compared. 

When the applicant is crediting a different aging management program than recommended in 

the GALL Report, the reviewer should confirm that the alternate aging management program is 

valid to use for aging management and will be capable of managing the effects of aging as 

adequately as the aging management program recommended by the GALL Report.

3.5.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to which the 

LRA AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL Report for each of the following aging effect/aging 

mechanism combinations. Refer to Table 3.5-1, comparing the “Further Evaluation 

Recommended” column and the “Rev2 Item” column, for the AMR items that reference the 

following subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.5.2.2.1 PWR and BWR 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 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 
December 2010 3.5-3 NUREG-1800, Rev. 2

monitoring program to manage these aging effects. However, some plants may rely on a dewatering system to lower the site ground water level. If the plant’s current licensing basis (CLB) 

credits a de-watering system to control settlement, the GALL Report recommends further 

evaluation to verify the continued functionality of the de-watering system during the 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 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 Section III, 

Division 2, specifies the concrete temperature limits for normal operation or any other long-term 

period. The GALL Report recommends further evaluation of a plant-specific aging management 

program if any portion of the concrete containment components 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 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 RLSB-1 (Appendix A.1 of this SRP-LR).

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 Section XI, Subsection IWE, and 10 CFR Part 50, 

Appendix J, to manage this aging effect. The GALL Report recommends further 

evaluation of plant-specific programs to manage this aging effect if corrosion is indicated 

from the IWE examinations. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR).

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 Section XI, 

Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. The 

GALL Report recommends further evaluation of plant-specific programs to manage this 

aging effect if corrosion is significant. Acceptance criteria are described in Branch 

Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

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 

containments. The existing program relies on ASME Section XI, Subsection IWE to 

manage this aging effect. The GALL Report recommends further evaluation of plantspecific programs to manage this aging effect if corrosion is significant. Acceptance 

criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRPLR). 
NUREG-1800, Rev. 2 3.5-4 December 2010

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 

separately in Section 4.5, “Concrete Containment Tendon Prestress Analysis,” of this SRP-LR.

3.5.2.2.1.5 Cumulative Fatigue Damage

If included in the current licensing basis, fatigue analyses of suppression pool steel shells 

(including welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, 

and penetration bellows) for all types of PWR and BWR containments and BWR vent header, 

vent line bellows, and downcomers 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 

separately in Section 4.6, “Containment Liner Plates, Metal Containments, and Penetrations 

Fatigue Analysis,” of this SRP-LR. 

3.5.2.2.1.6 Cracking due to Stress Corrosion Cracking

Cracking due to stress corrosion cracking of stainless steel penetration bellows and dissimilar 

metal welds could occur in all types of PWR and BWR containments. The existing program 

relies on ASME Section XI, Subsection IWE and10 CFR Part 50, Appendix J, to manage this 

aging effect. The GALL Report recommends further evaluation of additional appropriate 

examinations/evaluations implemented to detect these aging effects for stainless steel 

penetration bellows and dissimilar metal welds. 

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. The GALL Report recommends further 

evaluation 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 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 Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR).

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. The GALL Report recommends further evaluation if leaching is observed in 

accessible areas that impact intended functions. Acceptance criteria are described in Branch 

Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).
December 2010 3.5-5 NUREG-1800, Rev. 2

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 belowgrade inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures. The GALL 

Report recommends further evaluation 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 below-grade 

inaccessible concrete areas for Groups 1-5 and 7-9 structures. The GALL Report 

recommends further evaluation of inaccessible areas of these Groups of structures if 

concrete was not constructed in accordance with the recommendations in the GALL

Report.

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 de-watering system 

to lower the site ground water level. If the plant’s CLB credits a de-watering system, the 

GALL Report recommends verification of the continued functionality of the de-watering 

system during the period of extended operation. The GALL Report recommends no 

further evaluation 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. The GALL Report recommends further evaluation 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 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). The GALL Report recommends further 

evaluation 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 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 Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).
NUREG-1800, Rev. 2 3.5-6 December 2010

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures

The GALL Report recommends further evaluation 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 Report, Chapter XI.S7, “Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” 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 belowgrade inaccessible concrete areas of Group 6 structures. The GALL Report 

recommends further evaluation 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 below-grade 

inaccessible reinforced concrete areas of Group 6 structures. The GALL 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 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

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. The GALL Report recommends further evaluation if leaching is 

observed in accessible areas that impact intended functions. Acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

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 stress corrosion cracking and loss of material due to pitting and crevice 

corrosion could occur for Group 7 and 8 stainless steel tank liners exposed to standing water. 

The GALL Report recommends further evaluation of plant-specific programs to manage these 

aging effects. The acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR).

3.5.2.2.2.5 Cumulative Fatigue Damage due to Fatigue

Fatigue of component support members, anchor bolts, and welds for Groups B1.1, B1.2, and 

B1.3 component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis 

exists. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The evaluation 

of this TLAA is addressed separately in Section 4.3, “Metal Fatigue Analysis,” of this SRP-LR. 

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2 of this 

SRP-LR).

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).
December 2010 3.5-7 NUREG-1800, Rev. 2

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 Report, the NRC reviewer performs an audit of aging 

management programs credited in the LRA to confirm consistency with the GALL AMPs 

identified in the GALL Report, Chapters X and XI.

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP with all 

exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, the 

reviewer identifies a difference from the GALL Report AMP that should have been identified as 

an exception to the GALL Report AMP, this difference should be reviewed and properly 

dispositioned. The reviewer should document the disposition of all LRA-defined exceptions and 

staff-identified differences.

The LRA should identify any enhancements that are needed to permit an existing LRA AMP to 

be declared consistent with the GALL AMP to which the LRA AMP is compared. The reviewer is 

to confirm both that the enhancement, when implemented, would allow the existing LRA AMP to 

be consistent with the GALL AMP and that the applicant has a commitment in the FSAR 

supplement to implement the enhancement prior to the 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 AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.5.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

period of extended operation in the FSAR supplement should be appropriate, 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 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 3.0-1 of this SRP-LR provides 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-LR subsection.

3.5.3 Review Procedures

For each area of review, the review procedures below are to be followed.

3.5.3.1 AMR Results Consistent with the GALL Report 

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to GALL in its LRA. In making this determination, the 
NUREG-1800, Rev. 2 3.5-8 December 2010

reviewer confirms that the applicant has provided a brief description of the system, components, 

materials, and environment. The reviewer also confirms that the applicant has stated that the 

applicable aging effects and industry and plant-specific operating experience have been 

reviewed by the applicant and are evaluated in the GALL Report. 

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL Report. Performance of this review requires 

the reviewer to confirm that the applicant has identified those aging effects for the structures 

and component supports that are contained in the GALL Report as applicable to its plant.

3.5.3.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 AMR item to which the LRA 

AMR item is compared identifies that further evaluation is recommended, then additional criteria 

apply as identified by the GALL Report for each of the following aging effect/aging mechanism 

combinations.

3.5.3.2.1 PWR and BWR 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

The GALL Report recommends further evaluation 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 de-watering system is relied upon to control settlement. The reviewer 

reviews and confirms that, if the applicant credits a de-watering system in its CLB, the applicant 

has committed to monitor the functionality of the de-watering system under the applicant’s 

ASME Code Section XI, Subsection IWL or the structures monitoring program. If not, the 

reviewer evaluates the plant-specific program for monitoring the de-watering system during the 

period of extended operation.

3.5.3.2.1.2 Reduction of Strength and Modulus due to Elevated Temperature

The GALL Report recommends further evaluation of programs to manage reduction of strength 

and modulus of concrete due to elevated temperature for PWR and BWR concrete and steel 

containments. The GALL Report notes that the implementation of ASME 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. 

The GALL Report recommends that a plant-specific evaluation 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). 

The GALL Report also states that 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 
December 2010 3.5-9 NUREG-1800, Rev. 2

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 the limits are exceeded the reviewer reviews 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 period of extended operation.

3.5.3.2.1.3 Loss of Material due to General, Pitting, and Crevice Corrosion 

1. The GALL Report identifies programs to manage loss of material due to general, pitting,

and crevice corrosion in 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 aging management program consists of ASME 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 

shall 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, the GALL Report recommends further evaluation of plant-specific 

programs to manage the aging effects for inaccessible areas if specific 

recommendations defined in the GALL Report cannot be satisfied. The reviewer reviews 

the applicant’s proposed aging management program 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 Report identifies programs to manage loss of material due to general, pitting,

and crevice corrosion in steel torus shell of Mark I containments. The aging 

management program consists of ASME Section XI, Subsection IWE, and 10 CFR Part 

50, Appendix J, leak tests. In addition, the GALL Report recommends further evaluation 

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 operating 

experience that identified a number of incidences of torus corrosion. The reviewer 

reviews the applicant’s proposed aging management program 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 re-coating of the torus, if necessary. 

3. The GALL 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. The GALL Report 

recommends GLAL AMP XI.S1, “ASME Section XI, Subsection IWE,” for aging 

management. In addition, the GALL Report recommends further evaluation of plantspecific programs to manage the aging effects if plant operating experience identified 

significant corrosion of the torus ring girders, downcomers and suppression chambers. 
NUREG-1800, Rev. 2 3.5-10 December 2010

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 separately in 

Section 4.5 of this SRP-LR.

3.5.3.2.1.5 Cumulative Fatigue Damage

Fatigue analyses included in current licensing basis for the containment liner plate, penetrations 

(including penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of 

PWR and BWR containments and BWR suppression pool steel shells, 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 

separately in Section 4.6 of this SRP-LR. 

3.5.3.2.1.6 Cracking due to Stress Corrosion Cracking

The GALL Report recommends further evaluation of programs to manage cracking due to SCC 

for stainless steel penetration sleeves, dissimilar metal welds, and penetration bellows in all 

types of PWR and 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 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 bellows assemblies and dissimilar 

metal welds 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 

The GALL Report recommends further evaluation 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 ASTM C33-90, Fig. 1. A 

plant-specific program is not required if documented evidence confirms that where the existing 

concrete had air content of 3% to 8% (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 as identified in the GALL Report. 

Otherwise, the reviewer reviews the applicant’s proposed aging management program 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 

The GALL Report recommends further evaluation of programs to manage cracking due to 

expansion and reaction with aggregates in inaccessible areas of concrete elements of PWR and 
December 2010 3.5-11 NUREG-1800, Rev. 2

BWR concrete and steel containments. A plant-specific aging management program is not 

necessary if (1) investigations, tests, and petrographic examinations of aggregates performed in 

accordance with ASTM C295 and other ASTM reactivity tests, as required, can demonstrate 

that those aggregates do not adversely react within concrete or (2) for potentially reactive 

aggregates, aggregate concrete reaction is not significant if the structure was constructed in 

accordance with ACI 318. The reviewer confirms that the applicant has satisfied these 

conditions for inaccessible concrete as identified in the GALL Report. Otherwise, the reviewer 

reviews the applicant’s proposed aging management program 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.

3.5.3.2.1.9 Increase in Porosity and Permeability due to Leaching of Calcium 

Hydroxide and Carbonation

The GALL Report recommends further evaluation 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 aging management program 

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 as identified in the GALL Report. 

Otherwise, the reviewer reviews the applicant’s proposed aging management program 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. The GALL Report recommends further evaluation 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, Fig. 1. A plant-specific 

program is not required if documented evidence confirms that where the existing 

concrete had air content of 3% to 8% 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 as 

identified in the GALL Report. Otherwise, the reviewer reviews the applicant’s proposed 

aging management program 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. The GALL Report recommends further evaluation to determine if a plant-specific 

program is required to manage cracking due to expansion from reaction with aggregates

in below-grade inaccessible concrete areas of Groups 1-5 and 7-9 structures. A plantspecific program is not required if (1) investigations, tests, and petrographic 
NUREG-1800, Rev. 2 3.5-12 December 2010

examinations of aggregates performed in accordance with ASTM C295 and other ASTM 

reactivity tests, as required, can demonstrate that those aggregates do not adversely 

react within reinforced concrete, or (2) for potentially reactive aggregates, aggregatereinforced concrete reaction is not significant if the structure was constructed in 

accordance with ACI 318.The reviewer confirms that the applicant has satisfied these 

conditions as identified in the GALL Report. Otherwise, the reviewer reviews the 

applicant’s proposed aging management program to verify that, where appropriate, an 

effective inspection program has been developed and implemented to ensure that the 

aging effect is adequately managed.

3. The GALL Report recommends further evaluation 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 concrete areas of Groups 1-3, and 5-9 structures if a de-watering system is 

relied upon to manage the aging effect. The reviewer confirms that, if the applicant’s 

plant credits a de-watering system in its CLB, the applicant has committed to monitor the 

functionality of the de-watering system under the applicant’s structures monitoring 

program. If not, the reviewer reviews and evaluates the plant-specific program for 

monitoring the de-watering system during the period of extended operation.

4. The GALL Report recommends further evaluation 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 plantspecific aging management program 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 as identified in the GALL Report. Otherwise, 

the reviewer reviews the applicant’s proposed aging management program 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

The GALL Report recommends further evaluation of programs to manage reduction of strength 

and modulus of concrete structures due to elevated temperature for PWR and BWR safetyrelated and other structures. 

The GALL Report recommends that a plant-specific evaluation 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). 

The GALL Report also states that 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 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 
December 2010 3.5-13 NUREG-1800, Rev. 2

proposed programs on a case-by-case basis to ensure that the effects of elevated temperature 

will be adequately managed during the period of extended operation.

3.5.3.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures 

The GALL Report recommends further evaluation 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 Report, Chapter XI.S7, “Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” 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 belowgrade inaccessible concrete areas of Group 6 structures. Further evaluation is needed 

for plants that are located in moderate to severe weathering conditions (weathering 

index >100 day-inch/yr) (NUREG-1557, Ref. 7). The weathering index for the continental 

US is shown in ASTM C33-90, Fig. 1. A plant-specific program is not required if 

documented evidence confirms that where the existing concrete had air content of 3% to 

8% 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 as 

identified in the GALL Report. Otherwise, the reviewer reviews the applicant’s proposed 

aging management program 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 below-grade 

inaccessible concrete areas of Group 6 structures. The GALL Report recommends 

further evaluation to determine if a plant-specific program is required to manage the 

aging effect. A plant specific program is not required if (1) investigations, tests, and 

petrographic examinations of aggregates performed in accordance with ASTM C295 and 

other ASTM reactivity tests, as required, can demonstrate that those aggregates do not 

adversely react within reinforced concrete or (2) for potentially reactive aggregates, 

aggregate-reinforced concrete reaction is not significant if the structure was constructed 

in accordance with ACI 318. The reviewer confirms that the applicant has satisfied these 

conditions for inaccessible concrete as identified in the GALL Report. Otherwise, the 

reviewer reviews the applicant’s proposed aging management program to verify that, 

where appropriate, an effective 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. The GALL Report recommends further evaluation to determine if a plantspecific program is required to manage the aging effect. A plant-specific program is not 

required for the reinforced 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 as identified in 

the GALL Report. Otherwise, the reviewer reviews the applicant’s proposed aging 

management program to verify that, where appropriate, an effective inspection program 
NUREG-1800, Rev. 2 3.5-14 December 2010

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

The GALL Report recommends further evaluation of plant-specific programs to manage 

cracking due to SCC and loss of material due to pitting and crevice corrosion for stainless steel 

tank liners exposed to standing water. The reviewer reviews the applicant’s proposed aging 

management program on a case-by-case basis to ensure that the intended functions will be 

maintained during the period of the extended operation.

3.5.3.2.2.5 Cumulative Fatigue Damage

Fatigue of support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 

component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The evaluation of this 

TLAA is addressed separately in Section 4.3 of this SRP-LR. 

3.5.3.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

The applicant’s aging management programs for license renewal 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 license renewal. 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.

3.5.3.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

The reviewer should confirm that the applicant, in their LRA, 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 Report or a plant-specific program. Review 

procedures are described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR). 

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA 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 LRA, between the LRA AMP and the GALL Report AMP, with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA AMP with this difference satisfies 10 CFR 
December 2010 3.5-15 NUREG-1800, Rev. 2

54.21(a)(3). The reviewer should document the basis for accepting enhancements, exceptions,

or differences. The AMPs evaluated in the GALL Report pertinent to the containments, 

structures, and component supports are summarized in Table 3.5-1 of this SRP-LR. The “Rev 2 

Item” (for 2010) and “Rev1 Item” (for 2005 counterpart) columns identify the AMR item numbers

in the GALL Report, Chapters II and III, presenting detailed information summarized by this row.

Table 3.5-1 of this SRP-LR may identify a plant-specific aging management program. If the 

applicant chooses to use a plant-specific program that is not a GALL AMP, the NRC reviewer 

should confirm that the plant-specific program satisfies the criteria of Branch Technical Position 

RLSB-1 (Appendix A.1.2.3 of this SRP-LR).

3.5.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in its FSAR supplement information 

equivalent to that in Table 3.0-1 for aging management of the containments, structures, and 

component supports. Table 3.5-2 lists the AMPs that are applicable for this SRP-LR subsection. 

The reviewer also confirms that the applicant has provided information for Subsection 3.5.3.3, 

“AMR Results Not Consistent with or Not Addressed in the GALL Report,” equivalent to that in 

Table 3.0-1.

The 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 and finds it acceptable 

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.

As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments, to be completed before the period of extended operation. The 

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 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 

containments, structures, and component supports components will be 

adequately managed so that the intended functions will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(3). 

The staff also reviewed the applicable FSAR Supplement program summaries 

and concludes that they adequately describe the AMPs credited for managing 
NUREG-1800, Rev. 2 3.5-16 December 2010

aging of the containments, structures, and component supports, as required by 

10 CFR 54.21(d).

3.5.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.

3.5.6 References

1. 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants,” Office 

of the Federal Register, National Archives and Records Administration, 2009.

2. 10 CFR Part 50.55a, “Codes and Standards,” Office of the Federal Register, National 

Archives and Records Administration, 2009.

3. 10 CFR Part 50.59, “Changes, Tests, and Experiments,” Office of the Federal Register, 

National Archives and Records Administration, 2009.

4. 10 CFR Part 50, Appendix J, “Primary Reactor Containment Leakage Testing for WaterCooled Power Reactors,” Office of the Federal Register, National Archives and Records 

Administration, 2009.

5. 10 CFR Part 50.71, “Maintenance of Record, Making of Reports,” Office of the Federal 

Register, National Archives and Records Administration, 2009.

6. 10 CFR Part 50.65, “Requirements for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants,” Office of the Federal Register, National Archives and Records 

Administration, 2009.

7. 10 CFR 54.4, “Scope, Office of the Federal Register,” National Archives and Records 

Administration, 2009.

8. NRC Regulatory Guide 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants,” Revision 1, U.S. Nuclear Regulatory Commission, March 1978.

9. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.

10. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

11. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.

12. ASME 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,” The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 

CFR 50.55a, The American Society of Mechanical Engineers, New York, NY.
December 2010 3.5-17 NUREG-1800, Rev. 2

13. ASME 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,” The ASME Boiler and Pressure Vessel Code, 2004 

edition as approved in 10 CFR 50.55a, the American Society of Mechanical Engineers, New 

York, NY.

14. ASME Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components,” 

Subsection IWF, “Requirements for Class 1, 2, 3, and MC Component Supports of LightWater Cooled Power Plants,” The ASME Boiler and Pressure Vessel Code, 2004 edition as 

approved in 10 CFR 50.55a, The American Society of Mechanical Engineers, New York, 

NY.

15. NUMARC 93-01, Rev. 2, “Industry Guideline for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants” [Line-In/Line-Out Version], Nuclear Energy Institute, 

April 1996. 

16. NRC Regulatory Guide 1.160, Revision 2, “Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants,” March 1997.

17. NUREG-1557, October 1996, “Summary of Technical Information and Agreements from 

Nuclear Management and Resource Council Industry Report addressing License Renewal.”

18. ACI Standard 318, “Building Code Requirements for Reinforced Concrete and 

Commentary,” American Concrete Institute.
NUREG-1800, Rev. 2 3.5-18 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

PWR Concrete (Reinforced and Prestressed) and Steel Containments

BWR Concrete and Steel (Mark I, II, and III) Containments

1 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

elements, all

Cracking and distortion 

due to increased stress 

levels from settlement

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL” or Chapter XI.S6, 

"Structure Monitoring"

If a de-watering system is 

relied upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a de-watering 

system is relied 

upon to control 

settlement (See 

subsection 

3.5.2.2.1.1)

2 BWR/PWR Concrete: foundation; 

subfoundation

Reduction of foundation 

strength and cracking 

due to differential 

settlement and erosion 

of porous concrete 

subfoundation

Chapter XI.S6, 

“Structures Monitoring” 

If a de-watering system is 

relied upon for control of 

erosion, then the licensee 

is to ensure proper 

functioning of the dewatering system through 

the period of extended 

operation.

Yes, if a de-watering 

system is relied 

upon to control 

settlement (See 

subsection 

3.5.2.2.1.1)
December 2010 3.5-19 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

3 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; 

buttresses, Concrete: 

containment; wall; 

basemat, Concrete: 

basemat, concrete fillin annulus

Reduction of strength 

and modulus 

due to elevated 

temperature (>150°F 

general; >200°F local)

A plant-specific aging 

management program is 

to be evaluated.

Yes, if temperature 

limits are exceeded 

(See subsection 

3.5.2.2.1.2)

4 BWR Steel elements 

(inaccessible areas): 

drywell shell; drywell 

head; and drywell shell

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

Yes, if corrosion is 

indicated from the 

IWE examinations 

(See subsection 

3.5.2.2.1.3.1)

5 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, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

Yes, if corrosion is 

indicated from the 

IWE examinations 

(See subsection 

3.5.2.2.1.3.1)

6 BWR Steel elements: torus 

shell

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

Yes, if corrosion is 

significant 

Recoating of the 

torus is 

recommended. (See 

subsection 

3.5.2.2.1.3.2)
NUREG-1800, Rev. 2 3.5-20 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

7 BWR Steel elements: torus 

ring girders; 

downcomers;, Steel 

elements: suppression 

chamber shell (interior 

surface)

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE”

Yes, if corrosion is 

significant (See 

subsection 

3.5.2.2.1.3.3)

8 BWR/PWR Prestressing system: 

tendons

Loss of prestress 

due to relaxation; 

shrinkage; creep; 

elevated temperature

Yes, TLAA Yes, TLAA (See 

subsection 

3.5.2.2.1.4)

9 BWR/PWR 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 fatigue 

(Only if CLB fatigue 

analysis exists)

Yes, TLAA Yes, TLAA (See 

subsection 

3.5.2.2.1.5)

10 PWR Penetration sleeves; 

penetration bellows

Cracking 

due to stress corrosion 

cracking

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

Yes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.5.2.2.1.6)

11 BWR/PWR Concrete (inaccessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

Loss of material 

(spalling, scaling) and 

cracking 

due to freeze-thaw

Further evaluation is 

needed for plants that are 

located in moderate to 

severe weathering 

Yes, for plants 

located in moderate 

to severe 

weathering 
December 2010 3.5-21 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

dome; wall; basemat

conditions (weathering 

index >100 day-inch/yr) 

(NUREG-1557). 

conditions (See 

subsection 

3.5.2.2.1.7)

12 BWR/PWR Concrete (inaccessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

containment; wall; 

basemat, Concrete 

(inaccessible areas): 

basemat, concrete fillin annulus

Cracking 

due to expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed. 

Yes, if concrete is 

not constructed as 

stated function (See 

subsection 

3.5.2.2.1.8)

13 BWR/PWR Concrete (inaccessible 

areas): basemat, 

Concrete (inaccessible 

areas): dome; wall; 

basemat

Increase in porosity and 

permeability; loss of 

strength 

due to leaching of 

calcium hydroxide and 

carbonation

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed. 

Yes, if leaching is 

observed in 

accessible areas 

that impact intended 

function (See 

subsection 

3.5.2.2.1.9)

14 BWR/PWR Concrete (inaccessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(inaccessible areas): 

containment; wall; 

basemat

Increase in porosity and 

permeability; loss of 

strength 

due to leaching of 

calcium hydroxide and 

carbonation

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed. 

Yes, if leaching is 

observed in 

accessible areas 

that impact intended 

function (See 

subsection 

3.5.2.2.1.9)
NUREG-1800, Rev. 2 3.5-22 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

15 BWR/PWR Concrete (accessible 

areas): basemat

Increase in porosity and 

permeability; loss of 

strength 

due to leaching of 

calcium hydroxide and 

carbonation

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 

16 BWR/PWR Concrete (accessible 

areas): basemat, 

Concrete: containment; 

wall; basemat

Increase in porosity and 

permeability; cracking; 

loss of material 

(spalling, scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL,” or 

Chapter XI.S6, 

"Structures Monitoring"

No 

17 BWR Concrete (accessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses

Increase in porosity and 

permeability; cracking; 

loss of material 

(spalling, scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 

18 BWR/PWR Concrete (accessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(accessible areas): 

basemat

Loss of material 

(spalling, scaling) and 

cracking 

due to freeze-thaw

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 

19 BWR/PWR Concrete (accessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(accessible areas): 

Cracking 

due to expansion from 

reaction with 

aggregates

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 
December 2010 3.5-23 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

basemat, Concrete 

(accessible areas): 

containment; wall; 

basemat, Concrete 

(accessible areas): 

basemat, concrete fillin annulus

20 BWR/PWR Concrete (accessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(accessible areas): 

containment; wall; 

basemat

Increase in porosity and 

permeability; loss of 

strength 

due to leaching of 

calcium hydroxide and 

carbonation

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 

21 BWR/PWR Concrete (accessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses; reinforcing 

steel, Concrete 

(accessible areas): 

basemat; reinforcing 

steel, Concrete 

(accessible areas): 

dome; wall; basemat; 

reinforcing steel

Cracking; loss of bond; 

and loss of material 

(spalling, scaling) 

due to corrosion of 

embedded steel

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 

22 BWR Concrete (inaccessible 

areas): basemat; 

reinforcing steel

Cracking; loss of bond; 

and loss of material 

(spalling, scaling) 

due to corrosion of 

embedded steel

Chapter XI.S6, 

"Structures Monitoring"

No 
NUREG-1800, Rev. 2 3.5-24 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

23 BWR/PWR Concrete (inaccessible 

areas): basemat; 

reinforcing steel, 

Concrete (inaccessible 

areas): dome; wall; 

basemat; reinforcing 

steel

Cracking; loss of bond; 

and loss of material 

(spalling, scaling) 

due to corrosion of 

embedded steel

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL,” or Chapter XI.S6, 

"Structures Monitoring"

No 

24 BWR/PWR Concrete (inaccessible 

areas): dome; wall; 

basemat; ring girders; 

buttresses, Concrete 

(inaccessible areas): 

basemat, Concrete 

(accessible areas): 

dome; wall; basemat

Increase in porosity and 

permeability; cracking; 

loss of material 

(spalling, scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL,” or Chapter XI.S6, 

"Structures Monitoring"

No 

25 PWR Concrete (inaccessible 

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

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL,” or 

Chapter XI.S6, 

"Structures Monitoring"

No 

26 BWR/PWR Moisture barriers 

(caulking, flashing, and 

other sealants)

Loss of sealing 

due to wear, damage, 

erosion, tear, surface 

cracks, or other defects

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE”

No 

27 BWR/PWR penetration sleeves; 

penetration bellows, 

Steel elements: torus; 

vent line; vent header; 

vent line bellows; 

Cracking 

due to cyclic loading 

(CLB fatigue analysis 

does not exist)

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

No 
December 2010 3.5-25 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

downcomers, 

Suppression pool shell

28 BWR/PWR Personnel airlock, 

equipment hatch, CRD 

hatch

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

No 

29 BWR/PWR Personnel airlock, 

equipment hatch, CRD 

hatch: locks, hinges, 

and closure 

mechanisms

Loss of leak tightness 

due to mechanical wear 

of locks, hinges and 

closure mechanisms

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 

30 BWR/PWR Pressure-retaining 

bolting

Loss of preload 

due to self-loosening

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, "10 CFR 

Part 50, Appendix J"

No 

31 BWR/PWR Pressure-retaining 

bolting, Steel elements: 

downcomer pipes

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE”

No 

32 BWR/PWR Prestressing system: 

tendons; anchorage 

components

Loss of material 

due to corrosion

Chapter XI.S2, “ASME 

Section XI, Subsection 

IWL”

No 
NUREG-1800, Rev. 2 3.5-26 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

33 BWR/PWR Seals and gaskets Loss of sealing 

due to wear, damage, 

erosion, tear, surface 

cracks, or other defects

Chapter XI.S4, “10 CFR 

Part 50, Appendix J "

No 

34 BWR/PWR Service Level I 

coatings

Loss of coating integrity 

due to blistering, 

cracking, flaking, 

peeling, or physical 

damage

Chapter XI.S8, 

"Protective Coating 

Monitoring and 

Maintenance"

No 

35 BWR/PWR Steel elements 

(accessible areas): 

liner; liner anchors; 

integral attachments, 

Penetration sleeves, 

Steel elements 

(accessible areas): 

drywell shell; drywell 

head; drywell shell in 

sand pocket regions;, 

Steel elements 

(accessible areas): 

suppression chamber; 

drywell; drywell head; 

embedded shell; region 

shielded by diaphragm 

floor (as applicable), 

Steel elements 

(accessible areas): 

drywell shell; drywell 

head

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

No 
December 2010 3.5-27 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

36 BWR Steel elements: drywell 

head; downcomers

Fretting or lockup 

due to mechanical wear

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE”

No 

37 BWR Steel elements: 

suppression chamber 

(torus) liner (interior 

surface)

Loss of material 

due to general (steel 

only), pitting, and 

crevice corrosion

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE,“ and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J"

No 

38 BWR Steel elements: 

suppression chamber 

shell (interior surface)

Cracking 

due to stress corrosion 

cracking

Chapter XI.S1, “ASME 

Section XI, Subsection

IWE,” and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

No 

39 BWR Steel elements: vent 

line bellows

Cracking 

due to stress corrosion 

cracking

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE," and 

Chapter XI.S4, “10 CFR 

Part 50, Appendix J”

No 

40 BWR Unbraced 

downcomers, Steel 

elements: vent header; 

downcomers

Cracking 

due to cyclic loading 

(CLB fatigue analysis 

does not exist)

Chapter XI.S1, “ASME 

Section XI, Subsection 

IWE”

No 

41 BWR Steel elements: drywell 

support skirt, Steel 

elements (inaccessible 

areas): support skirt

None None NA - No AEM or 

AMP
NUREG-1800, Rev. 2 3.5-28 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

Safety-Related and Other Structures; and Component Supports

42 BWR/PWR Groups 1-3, 5, 7-

9:Concrete 

(inaccessible areas): 

foundation

Loss of material 

(spalling, scaling) and 

cracking 

due to freeze-thaw

Further evaluation is 

required for plants that 

are located in moderate 

to severe weathering 

conditions (weathering 

index >100 day-inch/yr) 

(NUREG-1557)

Yes, for plants 

located in moderate 

to severe 

weathering 

conditions (See 

subsection 

3.5.2.2.2.1.1)

43 BWR/PWR All Groups except 

Group 6:Concrete 

(inaccessible areas): all

Cracking 

due to expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed.

Yes, if concrete is 

not constructed as 

stated (See 

subsection 

3.5.2.2.2.1.2)

44 BWR/PWR All Groups: concrete: 

all

Cracking and distortion 

due to increased stress 

levels from settlement

Chapter XI.S6, 

“Structures Monitoring” 

If a de-watering system is 

relied upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a de-watering 

system is relied 

upon to control 

settlement (See 

subsection 

3.5.2.2.2.1.3)
December 2010 3.5-29 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

45 BWR Groups 1-3, 5-9: 

concrete: foundation; 

subfoundation

Reduction in foundation 

strength, cracking 

due to differential 

settlement,erosion of 

porous concrete 

subfoundation

Chapter XI.S6, 

“Structures Monitoring” 

If a de-watering system is 

relied upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a de-watering 

system is relied 

upon to control 

settlement (See 

subsection 

3.5.2.2.2.1.3)

46 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

Chapter XI.S6, 

“Structures Monitoring” 

If a de-watering system is 

relied upon for control of 

settlement, then the 

licensee is to ensure 

proper functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a de-watering 

system is relied 

upon to control 

settlement (See 

subsection 

3.5.2.2.2.1.3)

47 BWR/PWR Groups 1-5, 7-9: 

concrete (inaccessible 

areas): exterior aboveand below-grade; 

foundation

Increase in porosity and 

permeability; loss of 

strength 

due to leaching of 

calcium hydroxide and 

carbonation

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed.

Yes, if leaching is 

observed in 

accessible areas 

that impact intended 

function (See 

subsection 

3.5.2.2.2.1.4)
NUREG-1800, Rev. 2 3.5-30 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

48 BWR/PWR Groups 1-5: concrete: 

all

Reduction of strength 

and modulus 

due to elevated 

temperature (>150°F 

general; >200°F local)

A plant-specific aging 

management program is 

to be evaluated.

Yes, if temperature 

limits are exceeded 

(See subsection 

3.5.2.2.2.2)

49 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

Further evaluation is 

required for plants that 

are located in moderate 

to severe weathering 

conditions (weathering 

index >100 day-inch/yr) 

(NUREG-1557)

Yes, for plants 

located in moderate 

to severe 

weathering 

conditions (See 

subsection 

3.5.2.2.2.3.1)

50 BWR/PWR Groups 6: concrete 

(inaccessible areas): all

Cracking 

due to expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed.

Yes, if concrete is 

not constructed as 

stated See 

subsection 

3.5.2.2.2.3.2)

51 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

Further evaluation is 

required to determine if a 

plant-specific aging 

management program is 

needed.

Yes, if leaching is 

observed in 

accessible areas 

that impact intended 

function (See 

subsection 

3.5.2.2.2.3.3)

52 BWR/PWR Groups 7, 8 - steel 

components: tank liner

Cracking 

due to stress corrosion 

cracking; 

Loss of material 

due to pitting and 

A plant-specific aging 

management program is 

to be evaluated.

Yes, plant-specific 

(See subsection 

3.5.2.2.2.4)
December 2010 3.5-31 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

crevice corrosion

53 BWR/PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Cumulative fatigue 

damage 

due to fatigue 

(Only if CLB fatigue 

analysis exists)

Yes, TLAA Yes, TLAA (See 

subsection 

3.5.2.2.2.5)

54 BWR/PWR All groups except 6: 

concrete (accessible 

areas): all

Cracking 

due to expansion from 

reaction with 

aggregates

Chapter XI.S6, 

“Structures Monitoring”

No 

55 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

Chapter XI.S6, 

“Structures Monitoring”

No 

56 BWR/PWR Concrete: exterior 

above- and belowgrade; foundation; 

interior slab

Loss of material 

due to abrasion; 

cavitation

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

No 
NUREG-1800, Rev. 2 3.5-32 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

57 BWR/PWR Constant and variable 

load spring hangers; 

guides; stops

Loss of mechanical 

function 

due to corrosion, 

distortion, dirt, overload, 

fatigue due to vibratory 

and cyclic thermal loads

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

58 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

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

No 

59 BWR/PWR Group 6: concrete 

(accessible areas): all

Cracking; loss of bond; 

and loss of material 

(spalling, scaling) 

due to corrosion of 

embedded steel

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

No 
December 2010 3.5-33 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

60 BWR/PWR Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation

Loss of material 

(spalling, scaling) and 

cracking 

due to freeze-thaw

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

No 

61 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

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

No 

62 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

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam

inspections and 

maintenance programs.

No 
NUREG-1800, Rev. 2 3.5-34 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

63 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

Chapter XI.S6, 

"Structures Monitoring"

No 

64 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

Chapter XI.S6, 

“Structures Monitoring"

No 

65 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

Chapter XI.S6, 

"Structures Monitoring"

No 

66 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 

Chapter XI.S6, 

“Structures Monitoring”

No 
December 2010 3.5-35 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

embedded steel 

67 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

Chapter XI.S6, 

"Structures Monitoring"

No 

68 BWR/PWR High-strength structural 

bolting

Cracking 

due to stress corrosion 

cracking

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

69 BWR/PWR High-strength structural 

bolting

Cracking 

due to stress corrosion 

cracking

Chapter XI.S6, 

"Structures Monitoring“ 

Note: ASTM A 325, F 

1852, and ASTM A 490 

bolts used in civil 

structures have not 

shown to be prone to 

SCC. SCC potential need 

No 
NUREG-1800, Rev. 2 3.5-36 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

not be evaluated for 

these bolts.

70 BWR/PWR Masonry walls: all Cracking 

due to restraint 

shrinkage, creep, and 

aggressive environment

Chapter XI.S5, “Masonry 

Walls”

No 

71 BWR/PWR Masonry walls: all Loss of material 

(spalling, scaling) and 

cracking 

due to freeze-thaw

Chapter XI.S5, “Masonry 

Walls"

No 

72 BWR/PWR Seals; gasket; moisture 

barriers (caulking, 

flashing, and other 

sealants)

Loss of sealing 

due to deterioration of 

seals, gaskets, and 

moisture barriers 

(caulking, flashing, and 

other sealants)

Chapter XI.S6, 

“Structures Monitoring”

No 

73 BWR/PWR Service Level I 

coatings

Loss of coating integrity 

due to blistering, 

cracking, flaking, 

peeling, physical 

damage

Chapter XI.S8, 

"Protective Coating 

Monitoring and 

Maintenance"

No 

74 BWR/PWR Sliding support 

bearings; sliding 

support surfaces

Loss of mechanical 

function 

due to corrosion, 

distortion, dirt, debris, 

overload, wear

Chapter XI.S6, 

“Structures Monitoring”

No 
December 2010 3.5-37 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

75 BWR/PWR Sliding surfaces Loss of mechanical 

function 

due to corrosion, 

distortion, dirt, debris, 

overload, wear

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

76 BWR/PWR Sliding surfaces: radial 

beam seats in BWR 

drywell

Loss of mechanical 

function 

due to corrosion, 

distortion, dirt, overload, 

wear

Chapter XI.S6, 

“Structures Monitoring"

No 

77 BWR/PWR Steel components: all 

structural steel

Loss of material 

due to corrosion

Chapter XI.S6, 

“Structures Monitoring” 

If protective coatings are 

relied upon to manage 

the effects of aging, the 

structures monitoring 

program is to include 

provisions to address 

protective coating 

monitoring and 

maintenance.

No 

78 BWR/PWR Steel components: fuel 

pool liner

Cracking 

due to stress corrosion 

cracking; 

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, "Water 

Chemistry," and 

Monitoring of the spent 

fuel pool water level in 

accordance with technical 

specifications and 

leakage from the leak 

chase channels.

No, unless leakages 

have been detected 

through the SFP 

liner that cannot be 

accounted for from 

the leak chase 

channels
NUREG-1800, Rev. 2 3.5-38 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

79 BWR/PWR Steel components: 

piles

Loss of material 

due to corrosion

Chapter XI.S6, 

“Structures Monitoring”

No 

80 BWR/PWR Structural bolting Loss of material 

due to general, pitting 

and crevice corrosion

Chapter XI.S6, 

“Structures Monitoring”

No 

81 BWR/PWR Structural bolting Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

82 BWR/PWR Structural bolting Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S6, 

“Structures Monitoring”

No 
December 2010 3.5-39 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

83 BWR/PWR Structural bolting Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.S7, 

“Regulatory Guide 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants” or the 

FERC/US Army Corp of 

Engineers dam 

inspections and 

maintenance programs.

No 

84 BWR/PWR Structural bolting Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

85 BWR/PWR Structural bolting Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” for BWR 

water, and 

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

86 BWR/PWR Structural bolting Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

87 BWR/PWR Structural bolting Loss of preload 

due to self-loosening

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 
NUREG-1800, Rev. 2 3.5-40 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

88 BWR/PWR Structural bolting Loss of preload 

due to self-loosening

Chapter XI.S6, 

“Structures Monitoring”

No 

89 PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric 

Acid Corrosion”

No 

90 BWR/PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Loss of material 

due to general (steel 

only), pitting, and 

crevice corrosion

Chapter XI.M2, “Water 

Chemistry,” for BWR 

water, and 

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 
December 2010 3.5-41 NUREG-1800, Rev. 2

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

91 BWR/PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Loss of material 

due to general and 

pitting corrosion

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

92 BWR/PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Loss of material 

due to general and 

pitting corrosion

Chapter XI.S6, 

“Structures Monitoring”

No 

93 BWR/PWR Support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.S6, 

“Structures Monitoring”

No 

94 BWR/PWR Vibration isolation 

elements

Reduction or loss of 

isolation function 

due to radiation 

hardening, temperature, 

humidity, sustained 

vibratory loading

Chapter XI.S3, “ASME 

Section XI, Subsection 

IWF”

No 

95 BWR/PWR Aluminum, galvanized 

steel and stainless 

steel Support 

members; welds; 

bolted connections; 

support anchorage to 

building structure 

exposed to Air –

None None NA - No AEM or 

AMP
NUREG-1800, Rev. 2 3.5-42 December 2010

Table 3.5-1 Summary of Aging Management Programs for Containments, Structures and Component Supports Eva

of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended 

indoor, uncontrolled 
December 2010 3.5-43 NUREG-1800, Rev. 2

Table 3.5-2 Aging Management Programs Recommended for Containments, 

Structures, and Component Supports

GALL Report Chapter/AMP Program Name

Chapter XI.M2 Water Chemistry

Chapter XI.M10 Boric Acid Corrosion

Chapter XI.M18 Bolting Integrity 

Chapter XI.S1 ASME Section XI, Subsection IWE Inservice Inspection 

(IWE)

Chapter XI.S2 ASME Section XI, Subsection IWL Inservice Inspection 

(IWL) 

Chapter XI.S3 ASME Section XI, Subsection IWF Inservice inspection 

(IWF) 

Chapter XI.S4 10 CFR Part 50, Appendix J

Chapter XI.S5 Masonry Walls

Chapter XI.S6 Structures Monitoring

Chapter XI.S7 R.G. 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants

Chapter XI.S8 Protective Coating Monitoring and Maintenance 

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP

December 2010 3.6-1 NUREG-1800, Rev. 2

3.6 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND 

CONTROLS

Review Responsibilities

Primary - Branches assigned responsibility by PM as described in SRP-LR Section 3.0 of this 

SRP-LR

3.6.1 Areas of Review

This section addresses the AMR and the associated AMP of the electrical and instrumentation 

and controls (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 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 license 

renewal are electrical cables and connections, metal enclosed buses, fuse holders, high-voltage 

insulators, transmission conductors and connections, and switchyard bus and connections.

The responsible review organization is to review the following LRA AMR and AMP items 

assigned to it, per SRP-LR Section 3.0:

AMRs

• AMR results consistent with the GALL Report

• AMR results for which further evaluation is recommended by the GALL Report

• AMR results not consistent with or not addressed in the GALL Report

AMPs

• Consistent with GALL 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 NRC’s regulations in 10 CFR 54.21.

3.6.2.1 AMR Results Consistent with the GALL Report 

The AMRs and the AMPs applicable to the electrical and I&C components are described and 

evaluated in Chapter VI of NUREG-1801, “Generic Aging Lessons Learned (GALL) Report” 

(Ref. 2).

The applicant’s LRA should provide sufficient information for the NRC reviewer to confirm that 

the specific LRA AMR item and the associated LRA AMP are consistent with the cited GALL 
NUREG-1800, Rev. 2 3.6-2 December 2010

Report AMR item. The staff reviewer should then confirm that the LRA AMR item is consistent 

with the GALL Report AMR item to which it is compared. 

When the applicant is crediting a different AMP than recommended in the GALL 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 

Report.

3.6.2.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 Report AMR item to 

which the LRA AMR item is compared identifies that “further evaluation is recommended,” then 

additional criteria apply as identified by the GALL Report for each of the following aging 

effect/aging mechanism combinations. Refer to Table 3.6-1, comparing the “Further Evaluation 

Recommended” and the “Rev2 Item” columns, for the AMR items that reference the following 

subsections. The 2005 AMR item counterpart is provided in the “Rev1 Item” column.

3.6.2.2.1 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 evaluation of this TLAA is addressed 

separately in Section 4.4, “Environmental Qualification (EQ) of Electrical Equipment,” of this 

SRP-LR. 

3.6.2.2.2 Reduced Insulation Resistance due to Presence of Any Salt Deposits and 

Surface Contamination, and Loss of Material due to Mechanical Wear Caused 

by Wind Blowing on Transmission Conductors

Reduced insulation resistance due to presence of any salt deposits and surface contamination 

could occur in high-voltage insulators. The GALL Report recommends further evaluation of a 

plant-specific AMP for plants located such that the potential exists for salt deposits or surface 

contamination (e.g., in the vicinity of salt water bodies or industrial pollution). Loss of material 

due to mechanical wear caused by wind blowing on transmission conductors could occur in 

high-voltage insulators. The GALL Report recommends further evaluation of a plant-specific 

AMP to ensure that this aging effect is adequately managed. Acceptance criteria are described 

in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR). 

3.6.2.2.3 Loss of Material due to Wind-Induced Abrasion, Loss of Conductor Strength 

due to Corrosion, and Increased Resistance of Connection due to Oxidation 

or Loss of Pre-load

Loss of material due to wind-induced abrasion, loss of conductor strength due to corrosion, and 

increased resistance of connection due to oxidation or loss of pre-load could occur in 

transmission conductors and connections, and in switchyard bus and connections. The GALL 

Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is 

adequately managed. Acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR).
December 2010 3.6-3 NUREG-1800, Rev. 2

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

Acceptance criteria are described in Branch Technical Position IQMB-1 (Appendix A.2 of this 

SRP-LR).

3.6.2.3 AMR Results Not Consistent With or Not Addressed in the GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

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 Report, the NRC reviewer performs an audit of AMPs credited 

in the LRA to confirm consistency with the GALL AMPs identified in the GALL Report, Chapters 

X and XI.

If the applicant identifies an exception to any of the program elements of the cited GALL Report 

AMP, the LRA 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 LRA AMP, with 

all exceptions, would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the LRA AMP, 

the reviewer identifies a difference between the LRA AMP and the GALL Report AMP that 

should have been identified as an exception to the GALL Report AMP, the difference should be 

reviewed and properly dispositioned. The reviewer should document the disposition of all LRAdefined exceptions and staff-identified differences.

The LRA should identify any enhancements that are needed to permit an existing AMP to be 

declared consistent with the GALL Report AMP to which the LRA 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 Report AMP and also that the applicant has a 

commitment in the FSAR supplement to implement the enhancement prior to the 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 AMP, the NRC 

reviewer should confirm that the plant-specific program satisfies the criteria of Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR).

3.6.2.5 FSAR Supplement

The summary description of the programs and activities for managing the effects of aging for the 

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 

period of extended operation. The description should also contain any future aging management 

activities, including enhancements and commitments, to be completed before entering the 

period of extended operation. Table 3.0-1 of this SRP-LR provides 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-LR subsection.
NUREG-1800, Rev. 2 3.6-4 December 2010

3.6.3 Review Procedures

For each area of review, the following review procedures are to be followed:

3.6.3.1 AMR Results Consistent with the GALL Report 

The applicant may reference the GALL Report in its LRA, as appropriate, and demonstrate that 

the AMRs and AMPs at its facility are consistent with those reviewed and approved in the GALL 

Report. The reviewer should not conduct a re-review of the substance of the matters described 

in the GALL Report. If the applicant has provided the information necessary to adopt the finding 

of program acceptability as described and evaluated in the GALL Report, the reviewer should 

find acceptable the applicant’s reference to the GALL Report in its LRA. 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 applicant 

has stated that the applicable aging effects, and that industry and plant-specific operating 

experience have been reviewed by the applicant and are evaluated in the GALL Report.

Furthermore, the reviewer should confirm that the applicant has addressed operating 

experience identified after the issuance of the GALL 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 Report as applicable to its plant. 

3.6.3.2 AMR Results for Which Further Evaluation is Recommended by the GALL 

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 AMR item to which the LRA 

AMR item is compared identifies that “further evaluation is recommended,” then additional 

criteria apply as identified by the GALL 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 staff reviews the evaluation of this TLAA 

separately following the guidance in Section 4.4 of this SRP-LR. 

3.6.3.2.2 Reduced Insulation Resistance due to Presence of Any Salt Deposits and 

Surface Contamination, and Loss of Material due to Mechanical Wear Caused 

by Wind Blowing on Transmission Conductors

The GALL Report recommends a plant-specific AMP for the management of reduced insulation 

resistance due to presence of any salt deposits and surface contamination for plants located 

such that the potential exists for salt deposits or surface contamination (e.g., in the vicinity of 

salt water bodies or industrial pollution), and loss of material due to mechanical wear caused by 

wind blowing on transmission conductors in high-voltage insulators. 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. 
December 2010 3.6-5 NUREG-1800, Rev. 2

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 Pre-load

The GALL 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 pre-load 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 ensure 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 license renewal 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 

license renewal. 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.

3.6.3.3 AMR Results Not Consistent With or Not Addressed in the GALL Report

The reviewer should confirm that the applicant, in the license renewal application, 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 Report or in a plantspecific program. Review procedures are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR).

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 Report. If the applicant commits to an enhancement to make its LRA 

AMP consistent with a GALL Report AMP, then the reviewer is to confirm that this 

enhancement, when implemented, will make the LRA AMP consistent with the GALL Report 

AMP. If the applicant identifies, in the LRA AMP, an exception to any of the program elements 

of the GALL Report AMP, the reviewer is to confirm that the LRA 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 LRA, between the LRA AMP and the GALL Report AMP with which the LRA claims to be 

consistent, the reviewer should confirm that the LRA 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 Report pertinent to the electrical and I&C 

components are summarized in Table 3.6-1 of this SRP-LR. The “Rev 2 Item” (for 2010) and 

“Rev1 Item” (for 2005 counterpart) columns identify the AMR item numbers in the GALL Report, 

Chapters VI, presenting detailed information summarized by this row.
NUREG-1800, Rev. 2 3.6-6 December 2010

Table 3.6-1 of this SRP-LR may identify a plant-specific AMP. If the applicant chooses to use a 

plant-specific program that is not a GALL AMP, the NRC reviewer should confirm that the plantspecific program satisfies the criteria of Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR). 

3.6.3.5 FSAR Supplement

The reviewer confirms that the applicant has provided in its FSAR supplement information 

equivalent to that in Table 3.0-1 for aging management of the Electrical and I&C System. Table 

3.6-2 lists the AMPs that are applicable for this SRP-LR subsection. The reviewer also confirms 

that the applicant has provided information for Subsection 3.6.3.3, “AMR Results Not Consistent 

With or Not Addressed in the GALL Report,” equivalent to that in Table 3.0-1.

The 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.

As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before the period of extended operation. The 

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 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 electrical and instrumentation 

and controls components will be adequately managed so that the intended functions will 

be maintained consistent with the CLB for the period of extended operation, as required 

by 10 CFR 54.21(a)(3). 

The staff also reviewed the applicable FSAR Supplement program summaries and 

concludes that they adequately describe the AMPs credited for managing aging of 

electrical and instrumentation and controls, as required by 10 CFR 54.21(d).

3.6.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specified portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.
December 2010 3.6-7 NUREG-1800, Rev. 2

3.6.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants, LWR Edition” U.S. Nuclear Regulatory Commission, March 2007.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

3. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.
NUREG-1800, Rev. 2 3.6-8 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

1 BWR/PWR Electrical equipment subject 

to 10 CFR 50.49 EQ 

requirements composed of 

Various polymeric and 

metallic materials exposed to 

Adverse localized 

environment caused by heat, 

radiation, oxygen, moisture, 

or voltage

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 period 

of extended operation.

See the Standard Review 

Plan, Section 4.4, 

"Environmental 

Qualification (EQ) of 

Electrical Equipment," for 

acceptable methods for 

meeting the requirements 

of 10 CFR 54.21(c)(1)(i) 

and (ii). 

See Chapter X.E1, 

"Environmental 

Qualification (EQ) of 

Electric Components," of 

this report for meeting the 

requirements of 10 CFR 

54.21(c)(1)(iii).

Yes, TLAA (See 

subsection 

3.6.2.2.1)

2 BWR/PWR High-voltage insulators 

composed of Porcelain; 

malleable iron; aluminum; 

galvanized steel; cement 

exposed to Air – outdoor

Loss of material 

due to mechanical 

wear caused by wind 

blowing on 

transmission 

conductors

A plant-specific aging 

management program is 

to be evaluated

Yes, plantspecific (See 

subsection 

3.6.2.2.2)
December 2010 3.6-9 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

3 BWR/PWR High-voltage insulators 

composed of Porcelain; 

malleable iron; aluminum; 

galvanized steel; cement 

exposed to Air – outdoor

Reduced insulation

resistance 

due to presence of salt 

deposits or surface 

contamination

A plant-specific aging 

management program is 

to be evaluated for plants 

located such that the 

potential exists for salt 

deposits or surface 

contamination (e.g., in 

the vicinity of salt water 

bodies or industrial 

pollution)

Yes, plantspecific (See 

subsection 

3.6.2.2.2)

4 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, plantspecific (See 

subsection 

3.6.2.2.3)

5 BWR/PWR Transmission connectors 

composed of Aluminum; 

steel exposed to Air –

outdoor

Increased resistance of 

connection

due to oxidation or loss 

of pre-load

A plant-specific aging 

management program is 

to be evaluated

Yes, plantspecific (See 

subsection 

3.6.2.2.3)

6 BWR/PWR Switchyard bus and 

connections composed of 

Aluminum; copper; bronze; 

stainless steel; galvanized 

steel exposed to Air –

outdoor

Loss of material 

due to wind-induced 

abrasion; 

Increased resistance of 

connection 

due to oxidation or loss 

of pre-load

A plant-specific aging 

management program is 

to be evaluated

Yes, plantspecific (See 

subsection 

3.6.2.2.3)

7 BWR/PWR Transmission conductors 

composed of Aluminum; 

Steel exposed to Air –

outdoor

Loss of material 

due to wind-induced 

abrasion

A plant-specific aging 

management program is 

to be evaluated for ACAR 

and ACSR

Yes, plantspecific (See 

subsection 

3.6.2.2.3)
NUREG-1800, Rev. 2 3.6-10 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

8 BWR/PWR Insulation material for 

electrical cables and 

connections (including 

terminal blocks, fuse holders, 

etc.) composed of Various 

organic polymers (e.g., EPR, 

SR, EPDM, XLPE) exposed 

to Adverse localized 

environment caused by heat, 

radiation, or moisture

Reduced insulation 

resistance 

due to 

thermal/thermoxidative 

degradation of 

organics, radiolysis, 

and photolysis (UV 

sensitive materials 

only) of organics; 

radiation-induced 

oxidation; 

moisture intrusion

Chapter XI.E1, 

"Insulation Material for 

Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements"

No 

9 BWR/PWR Insulation material for

electrical cables and 

connections used in 

instrumentation circuits that 

are sensitive to reduction in 

conductor insulation 

resistance (IR) composed of 

Various organic polymers 

(e.g., EPR, SR, EPDM, 

XLPE) exposed to Adverse 

localized environment 

caused by heat, radiation, or 

moisture

Reduced insulation 

resistance 

due to 

thermal/thermoxidative 

degradation of 

organics, radiolysis, 

and photolysis (UV 

sensitive materials 

only) of organics; 

radiation-induced 

oxidation; 

moisture intrusion

Chapter XI.E2, 

"Insulation Material for 

Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits"

No 
December 2010 3.6-11 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

10 BWR/PWR Conductor insulation for 

inaccessible power cables 

greater than or equal to 400

volts (e.g., installed in 

conduit or direct buried) 

composed of Various organic 

polymers (e.g., EPR, SR, 

EPDM, XLPE) exposed to 

Adverse localized 

environment caused by 

significant moisture

Reduced insulation 

resistance 

due to moisture

Chapter XI.E3, 

"Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements"

No 

11 BWR/PWR Metal enclosed bus: 

enclosure assemblies 

composed of Elastomers 

exposed to Air – indoor, 

controlled or uncontrolled or 

Air – outdoor

Surface cracking, 

crazing, scuffing, 

dimensional change 

(e.g. “ballooning” and 

“necking”), shrinkage, 

discoloration, 

hardening and loss of 

strength

due to elastomer 

degradation

Chapter XI.E4, "Metal 

Enclosed Bus," or 

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping and 

Ducting Components"

No 

12 BWR/PWR Metal enclosed bus: 

bus/connections composed 

of Various metals used for 

electrical bus and 

connections exposed to Air –

indoor, controlled or 

uncontrolled or Air – outdoor

Increased resistance of 

connection 

due to the loosening of 

bolts caused by 

thermal cycling and 

ohmic heating

Chapter XI.E4, "Metal 

Enclosed Bus"

No 
NUREG-1800, Rev. 2 3.6-12 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

13 BWR/PWR Metal enclosed bus: 

insulation; insulators 

composed of Porcelain; 

xenoy; thermo-plastic organic 

polymers exposed to Air –

indoor, controlled or 

uncontrolled or Air – outdoor

Reduced insulation 

resistance 

due to 

thermal/thermoxidative 

degradation of 

organics/thermoplastics

, radiation-induced 

oxidation, 

moisture/debris 

intrusion, and ohmic 

heating

Chapter XI.E4, "Metal 

Enclosed Bus"

No 

14 BWR/PWR Metal enclosed bus: external 

surface of enclosure 

assemblies composed of 

Steel exposed to Air –

indoor, uncontrolled or Air –

outdoor

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.E4, "Metal 

Enclosed Bus," or 

Chapter XI.S6, 

"Structures Monitoring"

No 

15 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 and 

crevice corrosion

Chapter XI.E4, "Metal 

Enclosed Bus," or 

Chapter XI.S6, 

"Structures Monitoring"

No 
December 2010 3.6-13 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

16 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 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); 

fatigue 

due to ohmic heating, 

thermal cycling, 

electrical transients

Chapter XI.E5, "Fuse 

Holders"

No 

17 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 resistance of 

connection 

due to fatigue caused 

by frequent 

manipulation or 

vibration

Chapter XI.E5, "Fuse 

Holders" 

No aging management 

program is required for 

those applicants who can 

demonstrate these fuse 

holders are located in an 

environment that does 

not subject them to 

environmental aging 

mechanisms or fatigue 

caused by frequent 

manipulation or vibration

No 
NUREG-1800, Rev. 2 3.6-14 December 2010

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

18 BWR/PWR Cable connections (metallic 

parts) composed of Various 

metals used for electrical 

contacts exposed to Air –

indoor, controlled or 

uncontrolled or Air – outdoor

Increased resistance of 

connection 

due to thermal cycling, 

ohmic heating, 

electrical transients, 

vibration, chemical 

contamination, 

corrosion, and 

oxidation

Chapter XI.E6, "Electrical 

Cable Connections Not 

Subject to 10 CFR 50.49 

Environmental 

Qualification 

Requirements"

No 

19 PWR Connector contacts for 

electrical connectors 

exposed to borated water 

leakage composed of 

Various metals used for 

electrical contacts exposed 

to Air with borated water 

leakage

Increased resistance of 

connection 

due to corrosion of 

connector contact 

surfaces caused by 

intrusion of borated 

water

Chapter XI.M10, “Boric 

Acid Corrosion”

No 

20 BWR/PWR Transmission conductors 

composed of Aluminum 

exposed to Air – outdoor

Loss of conductor 

strength 

due to corrosion

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced (ACAR)

None 
December 2010 3.6-15 NUREG-1800, Rev. 2

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

Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

21 BWR/PWR Fuse holders (not part of 

active equipment): insulation 

material, Metal enclosed bus: 

external surface of enclosure 

assemblies composed of 

Insulation material: bakelite; 

phenolic melamine or 

ceramic; molded 

polycarbonate; other, 

Galvanized steel; aluminum, 

Steel exposed to Air –

indoor, controlled or 

uncontrolled

None None NA - No AEM or 

AMP
NUREG-1800, Rev. 2 3.6-16 December 2010

Table 3.6-2 Aging Management Programs Recommended for Electrical and 

Instrumentation and Control Systems

GALL Report Chapter/AMP Program Name

Chapter X.E1 Environmental Qualification (EQ) of Electric 

Components (TLAA)

Chapter XI.E1 Insulation Material for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements

Chapter XI.E2 Insulation Material for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in 

Instrumentation Circuits

Chapter XI.E3 Inaccessible Power Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements

Chapter XI.E4 Metal Enclosed Bus

Chapter XI.E5 Fuse Holders

Chapter XI.E6 Electrical Cable Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements

Chapter XI.M10 Boric Acid Corrosion

Chapter XI.M38 Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components

Chapter XI.S6 Structures Monitoring

Appendix for GALL Quality Assurance for Aging Management Programs

SRP-LR Appendix A Plant-specific AMP
December 2010 4-i NUREG-1800, Rev. 2

CHAPTER 4

TIME-LIMITED AGING ANALYSES

December 2010 4.1-1 NUREG-1800, Rev. 2

4.1 IDENTIFICATION OF TIME-LIMITED AGING ANALYSES

Review Responsibilities

Primary - Branch responsible for the TLAA issues

Secondary - Other branches responsible for engineering, as appropriate

4.1.1 Areas of Review

This review plan section addresses the identification of time-limited aging analyses (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 based on an 

explicitly assumed 40-year plant life (for example, aspects of the reactor vessel design). 

Pursuant to 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 CLB, which includes TLAAs, is not an area within the 

scope of the 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. However, the initial license

renewal applicants have found no such exemptions for their plants. It is an applicant’s option to 

include more analyses than those required by 10 CFR 54.21(c)(1). The 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 an FSAR supplement summary 

description for each TLAA that is identified in accordance with 10 CFR 54.3.

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, the staff should 

have reasonable assurance that there has been no omission of TLAAs from that list.

Pursuant to 10 CFR 54.3, TLAAs are those licensee calculations and analyses that:

1. Involve systems, structures, and components within the scope of license renewal, as 

delineated in 10 CFR 54.4(a);

2. Consider the effects of aging;

3. Involve time-limited assumptions defined by the current operating term, 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 
NUREG-1800, Rev. 2 4.1-2 December 2010

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 reviewer reviews the FSAR supplement for each TLAA identified as being within the scope 

of the LRA, as defined in 10 CFR 54.3.

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 UFSAR and other CLB documents, such as staff 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 (Ref. 1).

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 SRP-LR 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, change in dimension, change 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, or 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 
December 2010 4.1-3 NUREG-1800, Rev. 2

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 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 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 analysis 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, 

a licensee submitted a letter to the NRC committing to perform a TLAA that would 

address the concern in the generic letter. 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. 1). Table 4.1-2 provides a list of generic TLAAs that are included in the SRPLR. Table 4.1-3 provides a list of other 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.

As appropriate, staff members from other branches of NRR 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 staff 

members 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 granted pursuant to 10 CFR 50.12 and the exemption is in effect, the reviewer 
NUREG-1800, Rev. 2 4.1-4 December 2010

verifies that the applicant also has identified that exemption pursuant to 10 CFR 54.21(c)(2). 

However, the initial license renewal applicants have found no such exemptions for their plants.

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 staff’s evaluation supports conclusions of the 

following type, to be included in the staff’s safety evaluation report:

On the basis of its review, as discussed above, the 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 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein are used by the staff to evaluate conformance with NRC regulations.

4.1.6 REFERENCES

1. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.

2. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.
December 2010 4.1-5 NUREG-1800, Rev. 2

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

and Basis for Disposition

Example Disposition

NRC correspondence requests a utility to 

justify that unacceptable cumulative wear did 

not occur during the design life of control 

rods.

Does not qualify as a TLAA because the 

design life of control rods is less than 40 

years. Therefore, does not meet criterion (3) 

of the TLAA definition in 10 CFR 54.3.

Maximum wind speed of 100 mph is 

expected to occur once per 50 years.

Not a TLAA because it does not involve an 

aging effect.

Correspondence from the utility to the NRC 

states that the membrane on the 

containment basemat is certified by the 

vendor to last for 40 years.

The membrane was not credited in any safety 

evaluation, and therefore the analysis is not 

considered a TLAA. This example does not 

meet criterion (4) of the TLAA definition in 

10 CFR 54.3.

Fatigue usage factor for the pressurizer 

surge line was determined not to be an issue 

for the current license period in response to 

NRC Bulletin 88-11.

This example is a TLAA because it meets all 6 

criteria in the definition of TLAA in 10 CFR 

54.3. The utility’s fatigue design basis relies 

on assumptions defined by the 40-year 

operating life for this component, which is the 

current operating term.

Containment tendon lift-off forces are 

calculated for the 40-year life of the plant. 

These data are used during Technical 

Specification surveillance for comparing 

measured to predicted lift-off forces.

This example is a TLAA because it meets all 

6 criteria of the TLAA definition in 10 CFR 

54.3. The lift-off force curves are currently 

limited to 40-year values, and are needed to 

perform a required Technical Specification 

surveillance.

Table 4.1-2 Generic Time-Limited Aging Analyses

Reactor vessel neutron embrittlement (Subsection 4.2)

Metal fatigue (Subsection 4.3)

Environmental qualification of electrical equipment (Subsection 4.4)

Concrete containment tendon prestress (Subsection 4.5)

Inservice local metal containment corrosion analyses (Subsection 4.6)
NUREG-1800, Rev. 2 4.1-6 December 2010

Table 4.1-3 Examples of Potential Plant-Specific TLAAs

Intergranular separation in the heat-affected zone (HAZ) of reactor vessel low-alloy steel 

under austenitic SS cladding

Low-temperature overpressure protection (LTOP) analyses

Fatigue analysis for the main steam supply lines to the turbine-driven auxiliary feedwater 

pumps

Fatigue analysis of the reactor coolant pump flywheel

Fatigue analysis of polar crane

Flow-induced vibration endurance limit for the reactor vessel internals

Transient cycle count assumptions for the reactor vessel internals

Ductility reduction of fracture toughness for the reactor vessel internals

Leak before break

Fatigue analysis for the containment liner plate

Containment penetration pressurization cycles

Metal corrosion allowance

High-energy line-break postulation based on fatigue cumulative usage factor

Inservice flaw growth analyses that demonstrate structure stability for 40 years 
December 2010 4.2-1 NUREG-1800, Rev. 2

4.2 REACTOR VESSEL NEUTRON EMBRITTLEMENT ANALYSIS

Review Responsibilities

Primary - Branch responsible for the 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 vessel beltline region of light-water nuclear power reactors. Areas of review to ensure 

that the reactor vessel has adequate fracture toughness to prevent brittle failure during normal 

and off-normal operating conditions are (a) upper-shelf energy, (b) pressurized thermal shock 

(PTS) for pressurized water reactors (PWRs), (c) heat-up and cool-down (pressure-temperature 

limits) curves, (d) Boiling Water Reactor Vessel and Internals Project (BWRVIP)-05 analysis for 

elimination of circumferential weld inspection and analysis of the axial welds, and (e) other 

plant-specific TLAAs on reactor vessel neutron embrittlement.

The adequacy of the analyses for these five areas is reviewed for the 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’s (NRC’s) regulation in 10 CFR 54.21(c)(1).

4.2.2.1 Time-Limited Aging Analysis

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 extended period of 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 reactor vessel neutron embrittlement, the 

specific acceptance criteria depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), 

or (iii).

4.2.2.1.1 Upper-Shelf Energy (USE)

10 CFR Part 50 Appendix G (Ref. 1) paragraph IV.A.1 requires that the reactor vessel beltline 

materials have a Charpy upper-shelf energy of no less than 68 J (50 ft-lb) throughout the life of 

the reactor vessel, unless otherwise approved by the NRC. An applicant may take any one of

the following three approaches.
NUREG-1800, Rev. 2 4.2-2 December 2010

4.2.2.1.1.1 10 CFR 54.21(c)(1)(i)

The reactor vessel components evaluated in the existing upper-shelf energy analysis or NRCapproved equivalent margins analysis (EMA) are re-evaluated to demonstrate that the existing 

analysis remains valid during the period of extended operation because the neutron fluence 

projected to the end of the period of extended operation is bound by the fluence assumed in the 

existing analysis.

4.2.2.1.1.2 10 CFR 54.21(c)(1)(ii)

The reactor vessel components evaluated in the existing upper-shelf energy analysis or NRCapproved EMA are re-evaluated to consider the period of extended operation in accordance 

with 10 CFR Part 50, Appendix G.

10 CFR Part 50, Appendix G, Section IV.A.1 (the rule) requires applicants to take further 

corrective actions for those cases where the 75 ft-lbs (102 joules) unirradiated USE (UUSE) 

criterion or 50 ft-lbs (68 joules) end-of-life (EOL) USE criterion cannot be met (i.e., when the 

respective UUSE value falls below 75 ft-lbs or the EOL USE falls below 50 ft-lbs). When this 

occurs, the rule requires a licensee to submit a supplemental analysis for NRC approval for any 

case where the UUSE value is less than 75 ft-lbs (102 joules) or where the projected EOL USE 

value for a given material is projected to be less than the 50 ft-lbs (68 joules) acceptance criteria 

at the expiration of the operating license. Thus, if the USE value for a PWR reactor vessel (RV) 

material, as projected to the expiration of the period of extended operation, falls below either the

50 ft-lbs (68 joules) acceptance criterion or the USE value criterion specified in a previously 

NRC-approved EMA, or where the percent-drop in USE value for a BWR RV material, as 

projected to the expiration of the period of extended operation, falls below that percent-drop in 

USE value approved by the NRC in its safety evaluation of the BWRVIP’s generic EMA for 

BWRs, an applicant will need to submit a plant-specific engineering analysis (usually an EMA) 

for NRC approval as supplemental information for license renewal. Otherwise, failure to meet 

the USE requirements of 10 CFR Part 50, Appendix G for the RV materials as evaluated using 

the neutron fluence that are projected for the period of extended operation mandates imposition 

of additional commitments or license condition on USE for the license renewal application. 

4.2.2.1.1.3 10 CFR 54.21(c)(1)(iii)

Acceptance criteria under 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 period of extended operation.

4.2.2.1.2 Pressurized Thermal Shock (for PWRs)

For PWRs, 10 CFR 50.61 (Ref. 2) requires that the “reference temperature” for reactor vessel 

beltline materials evaluated at EOL fluence, 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 (270°F) for plates, forgings, and axial weld materials, and 149°C 

(300°F) for circumferential weld materials. 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 change of the projected material neutron fluence or change in the material properties in any 

of the reactor vessel beltline materials. Therefore, the RTPTS value must be calculated for the 

entire life of the facility, including the period of extended operation. The PTS TLAA may be 

handled as follows.
December 2010 4.2-3 NUREG-1800, Rev. 2

4.2.2.1.2.1 10 CFR 54.21(c)(1)(i)

The existing PTS analysis remains valid during the period of extended operation because the 

neutron fluence projected to the end of the period of extended operation is bound by the fluence 

assumed in the existing analysis.

4.2.2.1.2.2 10 CFR 54.21(c)(1)(ii)

The PTS analysis is re-evaluated to consider the period of extended operation in accordance 

with 10 CFR 50.61. An analysis may be performed in accordance with NRC Regulatory Guide 

(RG) 1.154 (Ref. 3) or 10 CFR 50.61a (Ref. 16) if the PTS screening criteria in 10 CFR 50.61 

are projected to be exceeded during the period of extended operation. 

4.2.2.1.2.3 10 CFR 54.21(c)(1)(iii)

The staff position for license renewal on this option is described in a May 27, 2004 letter from 

L.A. Reyes (EDO) to the Commission (Ref. 4), which states that if the applicant does not extend 

the TLAA, the applicant provides an assessment of the current licensing basis 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.

4.2.2.1.3 Pressure-Temperature (P-T) Limits 

10 CFR Part 50, Appendix G (Ref. 1) requires that the reactor pressure vessel (RPV) be 

maintained within established pressure-temperature (P-T) limits, including during any condition 

of normal operation. This includes heatup and cooldown. These limits specify the maximum 

allowable pressure as a function of reactor coolant temperature. As the reactor pressure vessel 

becomes embrittled and its fracture toughness is reduced, the allowable pressure (given the 

required minimum temperature) is reduced. 

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 (i.e., 32 EFPY or other licensed EFPY values at 

expiration of the current license). However, the P-T limits for the period of extended operation 

need not be submitted as part of the LRA since the P-T limits need to be updated through the 

10 CFR 50.90 licensing process when necessary for P-T limits that are located in the limiting 

conditions of operation (LCOs) of the Technical Specifications (TS). For those plants that have 

approved pressure-temperature limit reports (PTLRs), the P-T limits for the 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 current licensing basis, will ensure that the P-T limits for the period of 

extended operation will be updated prior to expiration of the P-T limit curves for the current 

period of operation.

P-T limits may be handled as follows.

4.2.2.1.3.1 10 CFR 54.21(c)(1)(i)

The existing P-T limits are valid during the period of extended operation because the neutron 

fluence projected to the end of the period of extended operation is bound by the fluence 

assumed in the existing analysis.
NUREG-1800, Rev. 2 4.2-4 December 2010

4.2.2.1.3.2 10 CFR 54.21(c)(1)(ii)

The P-T limits are reevaluated to consider the period of extended operation in accordance with 

10 CFR Part 50, Appendix G (Ref. 1).

4.2.2.1.3.3 10 CFR 54.21(c)(1)(iii)

Updated P-T limits for the period of extended operation must be available prior to entering the 

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 aging management programs within the scope of 

10 CFR 54.21(c)(1)(iii), such that P-T limits will be maintained through the period of extended 

operation.

4.2.2.1.4 Elimination of Circumferential Weld Inspection (for BWRs)

Some BWRs have an approved technical alternative, which eliminates the reactor vessel 

circumferential shell weld inspections for the current license term because they satisfy the 

limiting conditional failure probability for the circumferential welds at the expiration of the current 

license, based on BWRVIP-05 and the extent of neutron embrittlement (Refs. 5-7). These 

assessments are performed through the 10 CFR 50.55a process. If the applicant indicates that 

relief from circumferential weld examination will be made under 10 CFR 50.55a(a)(3), the 

applicant will manage this TLAA in accordance with 10 CFR 54.21(c)(1)(iii).

4.2.2.1.4.1 10 CFR 54.21(c)(1)(iii)

An applicant for renewal of a license should address this issue by noting that it will be handled 

through a re-application under 10 CFR 50.55a(a)(3). An applicant for a license renewal to 

operate, such a BWR may provide justification to extend this relief into the period of extended 

operation in accordance with BWRVIP-74-A (Ref. 8), which is the revised and NRC-approved 

version of BWRVIP-74 (Ref. 9). The staff’s review of BWRVIP-74 (Ref. 9) is contained in an 

October 18, 2001 letter to C. Terry, BWRVIP Chairman (Ref. 10). Appendix E of the staff’s final 

safety evaluation report (FSER) (Ref. 10) conservatively evaluated BWR RPV’s to have 64 

effective full-power years (EFPY), which is 10 EFPY greater than the maximum of what is 

realistically expected for the end of the license renewal period. Since this is a generic analysis, 

a licensee relying on BWRVIP-74-A should provide plant-specific information to demonstrate 

that at the end of the renewal period, the circumferential beltline weld materials meet the limiting 

conditional failure probability for circumferential welds specified in Appendix E of the FSER (Ref. 

10) and that operator training and procedures are utilized during the license renewal term to 

limit the frequency for cold over-pressure events to the amount specified in the NRC FSER (Ref. 

10). 

4.2.2.1.5 Axial Welds (for BWRs)

The staff’s SER contained in a letter to Carl Terry dated March 7, 2000, “Supplement to Final 

Safety Evaluation of the BWR Vessel and Internals Project BWRVIP-05 Report” (Ref. 11),

discussed the staff’s concern related to RPV failure frequency for axial welds and the BWRVIP’s 

analysis of the RPV failure frequency of axial welds. These discussions are also presented in 

the staff’s FSER of BWRVIP-74 (Ref. 10). The SER indicates that the RPV failure frequency 

due to failure of the limiting axial welds in the BWR fleet at the end of 40 years of operation is 

less than 5 x 10-6 per reactor year, given the assumptions on flaw density, distribution, and 
December 2010 4.2-5 NUREG-1800, Rev. 2

location described in the SER. Since the BWRVIP analysis was generic, a licensee relying on 

BWRVIP-74-A should monitor axial beltline weld embrittlement. The applicant may provide 

plant-specific information to demonstrate that the axial beltline weld materials at the extended 

period of operation meet the criteria specified in the report or have a program to monitor axial 

weld embrittlement relative to the values specified by the staff in its March 7, 2000 (Ref. 11) 

letter. 

4.2.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended 

operation in the FSAR supplement is appropriate, 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).

4.2.3 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 Analysis

For the first three areas of review for the analysis of reactor vessel 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, as 

follows.

4.2.3.1.1 Upper-Shelf Energy

4.2.3.1.1.1 10 CFR 54.21(c)(1)(i)

The projected 1⁄4T neutron fluence at the end of the period of extended operation is reviewed to 

verify that it is bound by the fluence assumed in the existing upper-shelf energy analysis.

Neutron Fluence: The applicant identifies (a) the neutron fluence at the 1⁄4T location for each 

beltline material at the expiration of the license renewal period, (b) the staff-approved 

methodology used to determine the neutron fluence or submits the methodology for staff review, 

and (c) whether the methodology follows the guidance in NRC RG 1.190 (Ref. 15). 

4.2.3.1.1.2 10 CFR 54.21(c)(1)(ii)

The documented results of the revised upper-shelf energy analysis based on the projected 

neutron fluence at the end of the period of extended operation are reviewed for compliance with 

10 CFR Part 50, Appendix G. The applicant may use NRC RG 1.99 Rev. 2 (Ref. 12) to project 

upper-shelf energy to the end of the period of extended operation. The applicant also may use 

ASME Code Section XI Appendix K (Ref. 13) for the purpose of performing an equivalent 

margins analysis to demonstrate that adequate protection for ductile failure is maintained to the 

end of the period of extended operation. The staff reviews the applicant’s methodology for this 

evaluation. Branch Position MTEB 5-3, “Fracture Toughness Requirements,” in Standard 
NUREG-1800, Rev. 2 4.2-6 December 2010

Review Plan (Ref. 14), Section 5.3.2, “Pressure Temperature Limits, Upper-Shelf Energy, and

Pressurized Thermal Shock,” provides additional NRC positions on estimations of USE values 

for reactor vessel beltline materials.

The staff confirms that the applicant has provided sufficient information for all Upper Shelf 

Energy (USE) and/or equivalent margins analysis calculations for the period of extended 

operation as follows:

Neutron Fluence: The applicant identifies (a) the neutron fluence at the 1⁄4T location for each 

beltline material at the expiration of the license renewal period, (b) the staff-approved 

methodology used to determine the neutron fluence or submits the methodology for staff review, 

and (c) whether the methodology follows the guidance in NRC RG 1.190 (Ref. 15). 

To confirm that the USE analysis meets the requirements of Appendix G of 10 CFR Part 50 at 

the end of the license renewal period, the staff determines whether:

1. For each beltline material, the applicant provides the unirradiated Charpy USE, and the 

projected Charpy USE at the end of the license renewal period, and whether the drop in 

Charpy USE was determined using the limit lines in Figure 2 of NRC RG 1.99, Revision 

2, or from surveillance data and the percentage copper.

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 approved topical report that contains the analysis. Information the staff 

considers to assess the equivalent margins analysis includes the unirradiated USE (if 

available) for the limiting material, its copper content, the fluence (1⁄4T and at 1-inch 

depth), the EOLE USE (if available), 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 

heatup/cooldown rate during normal operation.

For Boiling Water Reactors, the staff confirms that the beltline materials are evaluated in 

accordance with Renewal Applicant Action Item 10 in the staff’s SER for BWRVIP-74 (Letter to 

C. Terry dated October 18, 2001) (Ref.10). Action Item 10: To demonstrate that the beltline 

materials meet the Charpy USE criteria specified in Appendix B of BWRVIP-74-A or the NRC 

FSER (Ref. 10), the applicant demonstrates that the percent reduction in Charpy USE for their 

beltline materials is less than that specified for the limiting BWR/3-6 plates and the non-Linde 80 

submerged arc welds and that the percent reduction in Charpy USE for their surveillance weld 

and plate are less than or equal to the values projected using the methodology in NRC RG 1.99, 

Revision 2.

The applicant identifies whether there are two or more surveillance material samples available 

that are relevant to the RPV beltline materials. If there are two or more data points for a 

surveillance material, the applicant provides analyses of the data to determine whether the data 

are consistent with the NRC RG 1.99, Revision 2 methodology that was utilized in the BWRVIP74-A analyses.
December 2010 4.2-7 NUREG-1800, Rev. 2

4.2.3.1.1.3 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 period of extended operation is reviewed on a case-by-case 

basis.

4.2.3.1.2 Pressurized Thermal Shock (for PWRs)

4.2.3.1.2.1 10 CFR 54.21(c)(1)(i)

The projected clad-to-base metal interface neutron fluence at the end of the period of extended 

operation is reviewed to verify that it is bound by the fluence assumed in the existing PTS 

analysis.

Neutron Fluence: The applicant identifies the neutron fluence at the clad-to-base metal interface 

for each beltline material at the expiration of the license renewal period. The applicant identifies 

the staff-approved methodology used in determining the neutron fluence or submits the 

methodology for staff review and identifies whether the methodology followed the guidance in 

NRC RG 1.190 (Ref. 15).

4.2.3.1.2.2 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 period of extended operation are reviewed for compliance with 10 CFR 50.61. 

The staff confirms that the applicant has provided sufficient information for Pressurized Thermal 

Shock for the period of extended operation as follows:

Neutron Fluence: Identified the neutron fluence at the clad-to-base metal interface for each 

beltline material at the expiration of the license renewal period. Identified the staff-approved 

methodology used in determining the neutron fluence or submit the methodology for staff review

and identified whether the methodology followed the guidance in NRC RG 1.190 (Ref. 15).

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 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

(i.e., the mean value of the adjustment or shift in reference temperature caused by irradiation). 

The delta RTNDT is determined by multiplying a chemistry factor from the tables in 10 CFR 50.61 

by a fluence factor calculated from the neutron flux using an equation.

The second methodology relies on plant-specific surveillance data to determine the delta RTNDT. 

In this methodology, two or more sets of surveillance data are needed. A surveillance datum 

consists of a measured delta RTNDT for corresponding neutron fluence. 10 CFR 50.61 specifies 

a procedure and a criterion for determining whether the surveillance data are credible. For the 

surveillance data to be defined as credible, the difference in the predicted value and the 

measured value for delta RTNDT must be less than 28°F for weld metal. When a credible 
NUREG-1800, Rev. 2 4.2-8 December 2010

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. Then the standard deviation of the increase in the RTNDT

can be reduced from 28°F to 14°F for welds.

To confirm that the Pressurized Thermal Shock analysis results in RTPTS values below the 

screening criteria in 10 CFR 50.61 at the end of the license renewal period, 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, the 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 seta are available from other beltline materials, then provide an analysis of 

the data in accordance with Regulatory Guide 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 period of

extended operation, an analysis based on NRC RG 1.154 (Ref. 3) or 10 CFR 50.61a may be 

submitted for review.

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 period of extended operation will be reviewed on a case-bycase basis. 

The license renewal application provides an assessment of the current licensing basis 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.

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 

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 fluence value for the limiting material at end of license 

extended (EOLE),

(3) Provides the projected RTPTS value for the limiting material at EOLE, and 

(4) Provides the projected date and fluence values at which the limiting material will 

exceed the screening criteria in §50.61.
December 2010 4.2-9 NUREG-1800, Rev. 2

B. The applicant discusses aging management programs 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. The applicant briefly discusses the options that it is considering with respect to 

“resolving” the PTS issue through EOLE. It is anticipated that this discussion includes 

some or all of the following:

(1) Plant modifications (e.g., heating of ECCS 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 (e.g., using Regulatory Guide 1.154) which may 

be performed to show that the PTS risk for the facility is acceptably low through 

EOLE [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 (Ref. 16). 

4.2.3.1.3 Pressure-Temperature (P-T) Limits 

4.2.3.1.3.1 10 CFR 54.21(c)(1)(i)

The projected neutron fluence for the 1⁄4T and 3⁄4T locations at the end of the period of extended 

operation are bounded by the neutron fluences used to develop the existing P-T limit analysis. 

Neutron Fluence: The applicant identifies (a) the neutron fluence at the 1⁄4T and 3⁄4T locations for 

each beltline material at the expiration of the license renewal period, (b) the staff-approved 

methodology used to determine the neutron fluence or submits the methodology for staff review, 

and (c) whether the methodology follows the guidance in NRC RG 1.190 (Ref. 15). 

4.2.3.1.3.2 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 period of extended operation is reviewed for compliance 

with 10 CFR Part 50, Appendix G. The P-T limit evaluations are dependent upon the neutron 

fluence. 

Neutron Fluence: The applicant identifies (a) the neutron fluence at the 1⁄4T and 3⁄4T locations for 

each beltline material at the expiration of the license renewal period, (b) the staff-approved

methodology used to determine the neutron fluence or submits the methodology for staff review, 

and (c) whether the methodology follows the guidance in NRC RG 1.190 (Ref. 15). 

4.2.3.1.3.3 10 CFR 54.21(c)(1)(iii)

Updated P-T limits for the period of extended operation must be available prior to entering the 

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 aging management programs within the scope of 
NUREG-1800, Rev. 2 4.2-10 December 2010

10 CFR 54.21(c)(1)(iii), such that P-T limits will be maintained through the period of extended 

operation.

For Boiling Water Reactors, the staff confirms that the applicant addresses the following 

Renewal Applicant Action Item in the staff’s SER for BWRVIP-74 (Letter to C. Terry dated 

October 18, 2001) (Ref.10). 

Action Item 9: Appendix A of the BWRVIP-74-A Report 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 license renewal period.

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 60 years. 

4.2.3.1.4 Elimination of Circumferential Weld Inspection (for BWRs)

The staff verifies that the applicant has identified that, should the inspection relief be desired for 

the period of extended operation, an application will be made under 10 CFR 50.55a(a)(3) prior 

to entering the period of extended operation. If the applicant indicates that relief from 

circumferential weld examination will be made under 10 CFR 50.55a(a)(3), the applicant will 

manage this TLAA in accordance with 10 CFR 54.21(c)(1)(iii).

4.2.3.1.5 Axial Welds (for BWRs)

To demonstrate that the vessel has not been embrittled beyond the basis for the staff and 

BWRVIP analyses, the applicant should provide (a) a comparison of the neutron fluence, initial 

RTNDT, chemistry factor amounts of copper and nickel, delta RTNDT, and mean RTNDT of the 

limiting axial weld at the end of the license renewal period to the reference case in the BWRVIP 

and staff analyses and (b) an estimate of conditional failure probability of the RPV at the end of 

the license renewal term based on the comparison of the mean RTNDT for the limiting axial welds 

and the reference case. If this comparison does not indicate that the RPV failure frequency for 

axial welds is less than 5 x 10-6 per reactor year, the applicant should provide a probabilistic 

analysis to determine the RPV failure frequency for axial welds. Consistent with the staff’s 

supplemental safety evaluation report (SER) of BWR Vessel and Internals Project BWRVIP-05 

Report, dated May 7, 2000 (Ref. 11), the staff should ensure that the applicant’s plant is 

bounded by the BWRVIP-05 analysis or that the applicant has committed to a program to 

monitor axial weld embrittlement relative to the values specified by the staff in its May 7, 2000 

SER. The staff also confirms that the applicant has addressed the following Renewal Applicant 

Action Item in the staff’s SER for BWRVIP-74 (Letter to C. Terry dated October 18, 2001) 

(Ref.10).

Action Item 12: As indicated in the staff's March 7, 2000 letter to Carl Terry, a license renewal 

(LR) applicant shall monitor axial beltline weld embrittlement. One acceptable method is to 

determine the mean RTNDT of the limiting axial beltline weld at the end of the extended period of 

operation is less than the values specified in Table 1 of the staff’s Oct. 18, 2001 FSER (Ref. 10).

4.2.3.2 FSAR 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 reactor vessel neutron 
December 2010 4.2-11 NUREG-1800, Rev. 2

embrittlement TLAA. Table 4.2-1 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 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.

As noted in Table 4.2-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should verify that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before the period of extended operation. The 

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 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 staff’s safety evaluation report:

On the basis of its review, as discussed above, the staff concludes that the 

applicant has provided an acceptable demonstration, pursuant to 10 CFR 

54.21(c)(1), that, for the reactor vessel neutron embrittlement TLAA, [choose 

which is appropriate] (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. The staff also 

concludes that the FSAR supplement contains an appropriate summary 

description of the reactor vessel neutron embrittlement TLAA evaluation for the 

period of extended operation as reflected in the license condition.

4.2.5 IMPLEMENTATION

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein will be used by the staff in its evaluation of conformance with NRC 

regulations.

4.2.6 References

1. 10 CFR Part 50 Appendix G, “Fracture Toughness Requirements,” Office of the Federal 

Register, National Archives and Records Administration, 2010.

2. 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events,” Office of the Federal Register, National Archives and Records 

Administration, 2010.
NUREG-1800, Rev. 2 4.2-12 December 2010

3. Regulatory Guide 1.154, “Format and Content of Plant-Specific Pressurized Thermal Shock 

Safety Analysis Reports for Pressurized Water Reactors,” U.S. Nuclear Regulatory 

Commission, January 1987.

4. Letter to the Commission from L.A. Reyes (EDO), dated May 27, 2004 (ADAMS accession 

number ML041190564)

5. BWRVIP-05, “BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Shell Weld 

Inspection Recommendations,” EPRI TR-105697, September 1995.

6. Letter to Carl Terry of Niagara Mohawk Power Company, BWRVIP Chairman, from Gus C. 

Lainas of NRC, “Final Safety Evaluation of the BWR Vessel and Internals Project BWRVIP05 Report (TAC No. M93925),” July 28, 1998.

7. Generic Letter 98-05, “Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to 

Request Relief from Augmented Examination Requirements on Reactor Pressure Vessel 

Circumferential Shell Welds,” U.S. Nuclear Regulatory Commission, November 10, 1998.

8. BWRVIP-74-A, “BWR Vessels and Internals Project, BWR Reactor Pressure Vessel 

Inspection and Flaw Evaluation Guidelines for License Renewal,” EPRI TR-1008872, 

June 2003.

9. BWRVIP-74, “BWR Vessels and Internals Project, BWR Reactor Pressure Vessel Inspection 

and Flaw Evaluation Guidelines,” EPRI TR-113596, September 1999.

10. Letter to Carl Terry of Niagara Mohawk Power Company, BWRVIP Chairman, from 

Christopher Grimes, of NRC, “Acceptance for Referencing of EPRI Proprietary Report TR113596, 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 (10CFR54.21),” 

dated October 18, 2001.

11. Letter to Carl Terry of Niagara Mohawk Power Company, BWRVIP Chairman, from Jack R. 

Strosnider, Jr., of NRC, “Supplement to Final Safety Evaluation of the BWR Vessel and 

Internals Project BWRVIP-05 Report (TAC No. MA3395),” dated March 7, 2000.12.

12. Regulatory Guide 1.99 Rev. 2, “Radiation Embrittlement of Reactor Vessel Materials,” May, 

1988. 

13. Appendix K of ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power 

Plant Components,” 2004 Edition.

14. NUREG-0800, “U.S. Nuclear Regulatory Commission, Standard Review Plan,” U.S. Nuclear 

Regulatory Commission, March 2007.

15. Regulatory Guide 1.190 Rev. 0, “Calculational and Dosimetry Methods for Determining 

Pressure Vessel Neutron Fluence,” U.S. Nuclear Regulatory Commission, March 2001.

16. 75 FR 23, “Alternative Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events,” January 4, 2010.
December 2010 4.2-13 NUREG-1800, Rev. 2

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

TLAA Evaluation

TLAA Description of Evaluation Implementation 

Schedule*

Upper-shelf 

energy

10 CFR Part 50 Appendix G paragraph IV.A.1 requires 

that the reactor vessel beltline materials must have 

Charpy upper-shelf energy of no less than 50 ft-lb (68 J) 

throughout the life of the reactor vessel unless otherwise 

approved by the NRC. The upper-shelf energy has been 

determined to exceed 50 ft-lb (68 J) to the end of the 

period of extended operation.

Completed

Pressurized 

thermal shock 

(for PWRs)

For PWRs, 10 CFR 50.61 requires the “reference 

temperature RTPTS” for reactor vessel 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 “PTS screening criteria” are 

270°F (132°C) for plates, forgings, and axial weld 

materials, or 300°F (149°C) for circumferential weld 

materials. The “reference temperature” has been 

determined to be less than the “PTS screening criteria” 

at the end of the period of extended operation.

Completed

Pressuretemperature

(P-T) limits

10 CFR Part 50 Appendix G requires that heatup and 

cooldown of the 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 allowable pressure is reduced. 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 to consider the period of extended operation.

Update should 

be completed 

before the 

period of 

extended 

operation

Elimination of 

circumferential 

weld inspection 

and analysis of 

axial welds (for 

BWRs)

NRC has granted relief from the reactor vessel 

circumferential shell weld inspections because the 

applicant has demonstrated through plant-specific 

analysis that the plant meets the staff-approved 

BWRVIP-74-A Report and has provided sufficient 

information that the probability of vessel failure due to 

embrittlement of axial welds is low. If the applicant 

indicates that relief from circumferential weld 

examination will be made under 10 CFR 50.55a(a)(3), 

the applicant will manage this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii).

Re-submittal 

under 10 CFR 

50.55a(a)(3) 

should be 

completed 

before the 

period of 

extended 

operation

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 accordance with 

the neutron fluence projected for the period of extended 

operation, and why the TLAA is acceptable under either 
NUREG-1800, Rev. 2 4.2-14 December 2010

10 CFR 54.21 (c)(1)(i), (ii), or (iii).

* An applicant need not incorporate the implementation schedule into its FSAR. However, the 

reviewer should verify that the applicant has identified and committed in the license renewal 

application to any future aging management activities to be completed before the period of 

extended operation. The staff expects to impose a license condition on any renewed license 

to ensure that the applicant will complete these activities by no later than the committed date.
December 2010 4.3-1 NUREG-1800, Rev. 2

4.3 METAL FATIGUE 

Review Responsibilities

Primary - Branch responsible for the TLAA issues

Secondary - None

4.3.1 Area of Review

A metal component may progressively degrade and lose its structural integrity when it is 

subjected to fluctuating stresses, even at magnitudes less than the design static loads, due to a 

well-known degradation mechanism - fatigue. This mechanism of degradation can occur in flawfree components by developing cracks during services. ASME Section III (Ref. 1) requires a 

fatigue analysis for Class 1 components unless allowed by the Code to be exempted under 

applicable ASME Section III provisions. The analysis considers all transient loads based on the 

anticipated number of thermal and pressure transients, and includes calculation of a parameter 

“cumulative usage factor” (CUF) that is used for estimating the extent of fatigue damage in the 

component. The ASME Code limits the CUF to a value of less than or equal to one for 

acceptable fatigue design. A CUF below a value of one provides assurance that no crack has 

been formed. A CUF above a value of one allows for the possibility that a crack may form, and 

that if left untreated, the crack could propagate exponentially under fatigue loading and 

eventually lead to coolant leakage in reactor pressure boundary components, or even general 

structural failure. Metal fatigue of components may have been evaluated based on an assumed 

number of transients or cycles for the current operating term. The validity of such metal fatigue 

analysis is reviewed for the period of extended operation. 

Areas of review to ensure that the metal fatigue or flaw growth/tolerance evaluations are valid 

for the period of extended operation include:

1. CUF calculations for ASME Code Class 1 components designed to ASME Section III 

requirements, and other Codes that are based on a CUF calculation [the 1969 edition of 

ANSI B31.7 (Ref. 3) for Class 1 piping, ASME NC-3200 vessels, ASME NE 3200 Class 

MC components, and metal bellows designed to ASME NC-3649.4(e)(3), ND 

3649.4(e)(3), or NE-3366.2(e)(3)]. ASME Class 1 components, which include core 

support structures, are analyzed for metal fatigue.

2. Implicit fatigue-based maximum allowable stress calculations for piping components 

designed to USAS ANSI B31.1 (Ref. 2) requirements, and ASME Code Class 2 and 3 

components designed to ASME Section III design requirements that are similar to the 

guidance in ANSI B31.1. 

ANSI B31.1 applies only to piping and does not call for an explicit fatigue analysis. It 

specifies allowable stress levels based on the number of anticipated full thermal range 

transient cycles. The specific stress range reduction factors due to full thermal cycles are 

listed in Table 4.3-1. 

3. Environmental fatigue calculations for ASME Code Class 1 reactor coolant pressure 

boundary components.
NUREG-1800, Rev. 2 4.3-2 December 2010

Generic Safety Issue: The fatigue design criteria for nuclear power plant components 

have changed as the industry consensus codes and standards have developed. The 

fatigue design criteria for a specific component depend on the version of the design code 

that applied to that component, i.e., the code of record. There is a concern that the 

effects of the reactor coolant environment on the fatigue life of components were not 

adequately addressed by the code of record.

The NRC has decided that the adequacy of the code of record relating to metal fatigue is 

a potential safety issue to be addressed by the current regulatory process for operating 

reactors (Refs. 4 and 5). The effects of fatigue for the initial 40-year reactor license 

period were studied and resolved under Generic Safety Issue (GSI)-78, “Monitoring of 

Fatigue Transient Limits for reactor coolant system,” and GSI-166, “Adequacy of Fatigue 

Life of Metal Components” (Ref. 6). GSI-78 addressed whether fatigue monitoring was 

necessary at operating plants. As part of the resolution of GSI-166, an assessment was 

made of the significance of the more recent fatigue test data on the fatigue life of a 

sample of components in plants where Code fatigue design analysis had been 

performed. The efforts on fatigue life estimation and ongoing issues under GSI-78 and 

GSI-166 for 40-year plant life were addressed separately under a staff generic task 

action plan (Refs. 7 and 8). The staff documented its completion of the fatigue action 

plan in SECY-95-245 (Ref. 9).

SECY-95-245 was based on a study described in NUREG/CR-6260, “Application of 

NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components” 

(Ref. 10). In NUREG/CR-6260, sample locations with high fatigue usage were 

evaluated. Conservatisms in the original fatigue calculations, such as actual cycles 

versus assumed cycles, were removed, and the fatigue usage was recalculated using a 

fatigue curve considering the effects of the environment. The staff found that most of the 

locations would have a CUF of less than the ASME Code limit of 1.0 for 40 years. On the 

basis of the component assessments, supplemented by a 40-year risk study, the staff 

concluded that a backfit of the environmental fatigue data to operating plants could not 

be justified. However, because the staff was less certain that sufficient excessive 

conservatisms in the original fatigue calculations could be removed to account for an 

additional 20 years of operation for renewal, the staff recommended in SECY-95-245 

that the samples in NUREG/CR-6260 should be evaluated considering environmental 

effects for license renewal. GSI-190, “Fatigue Evaluation of Metal Components for 60-

year Plant Life,” was established to address the residual concerns of GSI-78 and GSI166 regarding the environmental effects on fatigue of pressure boundary components for 

60 years of plant operation. 

The scope of GSI-190 included design basis fatigue transients. It studied the probability 

of fatigue failure and its effect on core damage frequency (CDF) of selected metal 

components for 60-year plant life. The results showed that some components have 

cumulative probabilities of crack initiation and through-wall growth that approach one

within the 40- to 60-year period. The maximum failure rate (through-wall cracks per year) 

was in the range of 10E-2 per year, and those failures were generally associated with 

high cumulative usage factor locations and components with thinner walls, i.e., pipes 

more vulnerable to through-wall cracks. In most cases, the leakage from these throughwall cracks is small and not likely to lead to core damage. It was concluded that no 

generic regulatory action is necessary and that GSI-190 is resolved based on results of 

probabilistic analyses and sensitivity studies, interactions with the industry (NEI and 
December 2010 4.3-3 NUREG-1800, Rev. 2

EPRI), and different approaches available to licensees to manage the effects of aging 

(Refs. 11 and 12). 

However, the calculations supporting resolution of this issue, which included 

consideration of environmental effects, indicate the potential for an increase in the 

frequency of pipe leaks as plants continue to operate. Thus, the staff concluded that 

licensees are to address the effects of coolant environment on component fatigue life as 

aging management programs are formulated in support of license renewal. 

The applicant’s consideration of the effects of coolant environment on component fatigue 

life for license renewal is an area of review.

4. Potential fatigue assessments for BWR vessel internals components (potential TLAAs 

based on applicable applicant action items identified in applicable BWRVIP reports)

For Boiling Water Reactors, license renewal applications that reference the following 

BWR Vessels and Internals Project (BWRVIP) reports should identify and evaluate the 

projected fatigue CUFs as a potential TLAA issue, which may impact the structural 

integrity of the subject reactor pressure vessel internal components. 

• BWRVIP-18-A (Ref. 16, action item #4) for core spray internals

• BWRVIP-27-A (Ref. 17, action item #4) for standby liquid control system/core 

plate ∆P

• BWRVIP-47-A (Ref. 18, action item #4) for lower plenum. 

In addition, license renewal applications that reference the BWRVIP-74-A report (Ref. 

19) for reactor pressure vessel, should address the following renewal applicant action 

items in the staff’s SER for BWRVIP-74-A report.

Item #8: For the license renewal period, verify that the original fatigue analysis is valid 

and also addresses environmental fatigue for components mentioned in NUREG/CR6260. As a minimum, these components normally include reactor coolant pressure 

boundary components, such as reactor vessel head and shell components, reactor 

vessel flange bolting or stud components, reactor vessel nozzle components, and piping 

components, including safe-end locations.

Item #14: Components that have indications that were previously analytically evaluated 

in accordance with ASME Section XI Subsection IWB-3600 until the end of the 40-year 

service period shall be re-evaluated for the period corresponding to the license renewal 

term.

5. Potential fatigue-based flaw growth analyses or fatigue-based fracture mechanics 

analyses, including those for high-energy line breaks, reactor coolant pump (RCP) 

flywheels, reactor vessel metal bellows, and reactor vessel underclad cracking analyses 

(applicable to reactor vessels fabricated from SA-508 Class 2 or 3 forgings), as 

appropriate

The validity of these analyses is reviewed for the period of extended operation. The design 

criteria used to determine the postulated high-energy line break design locations include the 

calculated fatigue CUF based on the number of design transients assumed for the 40-year life 

of the plant. The aging effect of concern for the RCP flywheel is fatigue crack initiation and 
NUREG-1800, Rev. 2 4.3-4 December 2010

growth in the flywheel bore keyway from stresses due to starting the motor during start/stop 

cycles of the RCP during the 40-year design. Similarly, the primary containment process metal 

bellows are designed for a specific number of cycles of expansion and contraction for 40 years 

of operation. The fracture toughness (including the effects of neutron irradiation) and flaw 

growth analyses for underclad cracks that are postulated in the internal cladding of SA-508 

Class 2 and 3 alloy steel components are also based upon 40-year design transients.

4.3.2 Acceptance Criteria

The acceptance criteria for the areas of review described in Subsection 4.3.1 of this review plan 

section delineate acceptable methods for meeting the requirements of the NRC’s regulations in 

10 CFR 54.21(c)(1). 

4.3.2.1 Time-Limited Aging Analysis

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 extended period of operation, or

(iii) the effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

Specific acceptance criteria for metal fatigue are discussed in the following sub-sections.

4.3.2.1.1 ASME Code Class 1 Components Designed to ASME Section III and other 

Codes based on CUF

For components designed or analyzed to ASME Code Section III requirements for Class I 

components or other Codes that require a CUF calculation, the acceptance criteria, depending 

on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are discussed in the following subsections.

4.3.2.1.1.1 10 CFR 54.21(c)(1)(i)

The existing CUF calculations remain valid for the period of extended operation because the 

number of accumulated cycles for the design basis transients would not exceed the limits 

established for these transients.

4.3.2.1.1.2 10 CFR 54.21(c)(1)(ii)

The CUF calculation analyses are projected to the end of the extended period of operation 

based on projecting the cumulative number of transient occurrences for design basis transients 

through to the expiration of the period of extended operation. The resulting CUF values are 

verified to remain less than or equal to a CUF value of one for the period of extended operation.

4.3.2.1.1.3 10 CFR 54.21(c)(1)(iii)

In Chapter X.M1 of the GALL Report (Ref. 13), the staff has evaluated a program for monitoring 

and tracking the number of critical thermal and pressure transients for the selected components. 

The staff has determined that this program is an acceptable aging management program to 
December 2010 4.3-5 NUREG-1800, Rev. 2

address metal fatigue of the reactor coolant system components according to 10 CFR 

54.21(c)(1)(iii). The GALL Report may be referenced in a license renewal application and should 

be treated in the same manner as an approved topical report. In referencing the GALL 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 Report for the generic program apply to the applicant’s program.

4.3.2.1.2 Piping Components Designed to USAS ANSI B31.1 Requirements and ASME 

Code Class 2 and 3 Components Designed to ASME Section III Requirements

For piping designed or analyzed to B31.1 guidance or ASME Code Class 2 and 3 components 

designed to ASME Section III cyclic design requirements, the acceptance criteria, depending on 

the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are discussed in the following subsections.

4.3.2.1.2.1 10 CFR 54.21(c)(1)(i)

The maximum allowable stress range values for the existing fatigue analysis remain valid 

because the allowable limit for the number of full thermal range transient cycles would not be 

exceeded during the period of extended operation.

4.3.2.1.2.2 10 CFR 54.21(c)(1)(ii)

The maximum allowable stress range values are re-evaluated based on the projected number of 

assumed full thermal range transient cycles above a value of 7000 (refer to Table 4.3-1). The 

current stress range value in the design basis for the component is then compared to the 

reduced maximum allowable stress range value to make sure it is within the value of the newlyreduced limit, and to ensure that the design basis value remains acceptable during the period of 

extended operation.

4.3.2.1.2.3 10 CFR 54.21(c)(1)(iii)

The effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. Chapter X.M1 in the GALL Report provides an acceptable method for 

dispositioning fatigue analyses under 10 CFR 54.21(c)(1)(iii). Alternatively, the component could 

be replaced and the allowable stresses for the replacement will be sufficient as specified by the 

code during the period of extended operation. The analyses will be evaluated on a case-by-case 

basis to ensure that the aging effects will be managed such that the intended functions(s) will be 

maintained during the period of extended operation.

4.3.2.1.3 Environmental Fatigue Calculations for Code Class 1 Components

The staff recommendation for the closure of GSI-190 is contained in a December 26, 1999 

memorandum from Ashok Thadani to William Travers (Ref. 11). The staff recommended that 

licensees address the effects of the coolant environment on component fatigue life as aging 

management programs are formulated in support of license renewal. For reactor coolant 

pressure boundary components, one method acceptable to the staff for satisfying this 

recommendation is to assess the impact of the reactor coolant environment on a sample of 

critical components. These critical components should include, as a minimum, those selected in 

NUREG/CR-6260 (Ref. 10). Applicants should consider adding additional component locations 
NUREG-1800, Rev. 2 4.3-6 December 2010

if they are considered to be more limiting than those considered in NUREG/CR-6260. The 

sample of critical components can be evaluated by applying environmental correction factors to 

the existing ASME Code fatigue analyses. 

Applicants should consider adding additional component locations if they are considered to be 

more limiting than those considered in NUREG/CR-6260. The sample of critical components 

can be evaluated by applying environmental correction factors to the existing ASME Code 

fatigue analyses. Applicants should add additional plant specific component locations if they 

may be more limiting than those considered in NUREG/CR-6260. Environmental effects on 

fatigue for these critical components can be evaluated using one of the following sets of 

formulae:

• Carbon and Low Alloy Steels

o Those provided in NUREG/CR-6583 (Ref. 14), using the applicable ASME Section III 

fatigue design curve.

o Those provided in Appendix A of NUREG/CR-6909 (Ref. 21), using either the 

applicable ASME Section III fatigue design curve or the fatigue design curve for 

carbon and low alloy steel provided in NUREG/CR-6909 (Figures A.1 and A.2, 

respectively, and Table A.1).

o A staff approved alternative.

• Austenitic Stainless Steels

o Those provided in NUREG/CR-5704 (Ref. 15), using the applicable ASME Section III 

fatigue design curve.

o Those provided in NUREG/CR-6909 (Ref. 21), using the fatigue design curve for 

austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).

o A staff approved alternative.

• Nickel Alloys

o Those provided in NUREG/CR-6909 (Ref. 21), using the fatigue design curve for 

austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).

o A staff approved alternative.

Any one option may be used for calculating the CUFen for each material.

4.3.2.1.4 Potential Fatigue Assessments for BWR Vessel Internals Components

The acceptance criteria in Subsection 4.3.2.1.1 of this review plan section apply.

4.3.2.1.5 Potential Flaw Growth and Fracture Mechanics Analysis

Depending on the choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), the acceptance criteria are 

discussed in the following sub-sections.

4.3.2.1.5.1 10 CFR 54.21(c)(1)(i)

The existing analyses remain valid because the number of cycles assumed for the 40-year life 

would not be exceeded during the period of extended operation. 
December 2010 4.3-7 NUREG-1800, Rev. 2

4.3.2.1.5.2 10 CFR 54.21(c)(1)(ii)

The degree of flaw growth or increase in the stress intensity factor are projected based on the 

cumulative number of transient occurrences to the end of the period of extended operation. The 

newly-projected values are compared to the acceptance criteria for these parameters that were 

set in the original analysis.

4.3.2.1.5.3 10 CFR 54.21(c)(1)(iii)

The acceptance criteria under 10 CFR 54.21(c)(1)(iii) will be evaluated on a case-by-case basis 

to ensure that the aging effects will be managed such that the intended functions(s) of the 

subject components will be maintained during the period of extended operation.

Chapter X.M1 in the GALL Report may not be used as a basis for accepting fatigue-based flaw 

growth analyses or fracture mechanics analyses in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.2.2 FSAR Supplement 

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended 

operation in the FSAR supplement is appropriate such that later changes can be 

controlled by 10 CFR 50.59. The description should contain information associated with 

the TLAAs regarding the basis for determining that the applicant has made the 

demonstration required by 10 CFR 54.21(c)(1).

4.3.3 Review Procedures

For each area of review described in Subsection 4.3.1, the review procedures in the subsequent 

sub-sections should be followed.

4.3.3.1 Time-Limited Aging Analysis

4.3.3.1.1 ASME Code Class 1 Components Designed to ASME Section III and Other 

Codes based on CUF

For components designed or analyzed to ASME Class 1 requirements or other Codes that are 

based on a CUF calculation, the review procedures, depending on the applicant’s choice of 

10 CFR 54.21(c)(1)(i), (ii), or (iii), are discussed in the following sub-sections.

4.3.3.1.1.1 10 CFR 54.21(c)(1)(i)

The operating transient experience and a list of the assumed transients used in the existing 

CUF calculations for the current operating term are reviewed to ensure that the number of 

assumed transients would not be exceeded during the period of extended operation. For 

consistency purposes, the review also includes an assessment of the TLAA information against 

relevant design basis information and CLB information (including applicable cycle-counting 

requirements in technical specifications).
NUREG-1800, Rev. 2 4.3-8 December 2010

4.3.3.1.1.2 10 CFR 54.21(c)(1)(ii)

The operating transient experience is reviewed to ensure that the increased number of 

transients used for any re-analysis meets or exceeds the number of transients projected to the 

end of the period of extended operation. The revised CUF calculations are reviewed to ensure 

that the CUF remains less than or equal to one at the end of the period of extended operation. 

For consistency purposes, the review also includes an assessment of the TLAA information 

against relevant design basis information and CLB information (including applicable cyclecounting requirements in technical specifications).

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. In the latter case, the reviewer verifies that the 

requirements in 10 CFR 50.55a are met.

4.3.3.1.1.3 10 CFR 54.21(c)(1)(iii)

The applicant may reference Chapter X.M1 of the GALL Report in its license renewal 

application and use this GALL chapter 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 

of critical thermal and pressure transients for the selected reactor coolant system components. 

The reviewer verifies that the applicant has identified the appropriate program as described and 

evaluated in the GALL Report. The reviewer also ensures that the applicant has stated that its 

program contains the same program elements that the staff evaluated and relied upon in 

approving the corresponding generic program in the GALL 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 in technical 

specifications). No staff re-evaluation of the acceptability of the basis in the GALL Report 

Chapter X.M1 is necessary.

4.3.3.1.2 Piping Components Designed to USAS ANSI B31.1 Requirements and ASME 

Code Class 2 and 3 Components Designed to ASME Section III Requirements

For piping designed or analyzed to ANSI B31.1 guidance or ASME Code Class 2 and 3 

components designed to ASME Section III cyclic design requirements, the review procedures, 

depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are discussed in the 

following sub-sections.

4.3.3.1.2.1 10 CFR 54.21(c)(1)(i)

The staff reviews the relevant information in the TLAA, operating plant transient history, design 

basis, and CLB (including technical specification cycle counting requirements) to verify that the 

maximum allowable stress range values for the existing fatigue analysis remain valid for the 

period of extended operation and that the allowable limit for full thermal range transients will not 

be exceeded during the period of extended operation.

4.3.3.1.2.2 10 CFR 54.21(c)(1)(ii)

The maximum allowable stress range values are re-evaluated based on the projected number of 

full thermal range transient cycles above a value of 7000 (refer to Table 4.3-1). The reviewer 

confirms that (1) if the value of the number of equivalent full temperature cycles is above 7000, 
December 2010 4.3-9 NUREG-1800, Rev. 2

the applicant has reduced the maximum allowable stress range limit according to the reduction 

factors in the table, and (2) the design basis stress value for the component is within the newlyreduced allowable limit. The review includes all relevant design basis, operating history, CLB, 

and TLAA information, including technical specification cycle counting requirements.

4.3.3.1.2.3 10 CFR 54.21(c)(1)(iii)

The effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. Chapter X.M1 in the GALL Report provides an acceptable method to 

disposition these fatigue analyses under 10 CFR 54.21(c)(1)(iii). The 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 Chapter X.M1. 

In addition to continued monitoring and tracking, the components could be re-analyzed, 

inspected for cracking, repaired, or replaced. Such approaches will be evaluated on a case-bycase basis to ensure that the aging effects will be managed such that the intended functions(s) 

will be maintained during the period of extended operation.

4.3.3.1.3 Other Evaluations Based on CUF

The reviewer verifies that the applicant has addressed the staff recommendation for the closure 

of GSI-190 contained in a December 26, 1999 memorandum from Ashok Thadani to William 

Travers (Ref. 11). The reviewer verifies that the applicant has addressed the effects of the 

coolant environment on component fatigue life as aging management programs are formulated 

in support of license renewal. If an applicant has chosen to assess the impact of the reactor 

coolant environment on a sample of critical components, the reviewer verifies the following:

1. The critical components include a sample of high-fatigue usage locations. This sample is 

to include the locations identified in NUREG/CR-6260 (Ref. 10), as a minimum, and 

proposed additional locations based on plant specific considerations. 

2. The sample of critical components has been evaluated (1) by applying environmental 

correction factors to the existing ASME Code required CUF analyses, or (2) using the 

methodology provided in NUREG/CR-6909 (Ref. 21). If the Class 1 component was 

designed to a code not requiring CUF, a new environmental CUF calculation has been 

performed or is addressed in an appropriate license renewal commitment. 

3. Environmental effects on fatigue for these critical components have been evaluated 

using one of the following sets of formulae:

• Carbon and Low Alloy Steels

o Those provided in NUREG/CR-6583 (Ref. 14), using the applicable ASME 

Section III fatigue design curve.

o Those provided in Appendix A of NUREG/CR-6909 (Ref. 21), using either the 

applicable ASME Section III fatigue design curve or the fatigue design curve for 

carbon and low alloy steel provided in NUREG/CR-6909 (Figures A.1 and A.2, 

respectively, and Table A.1).

o A staff approved alternative.

• Austenitic Stainless Steels
NUREG-1800, Rev. 2 4.3-10 December 2010

o Those provided in NUREG/CR-5704 (Ref. 15), using the applicable ASME 

Section III fatigue design curve.

o Those provided in NUREG/CR-6909 (Ref. 21), using the fatigue design curve 

for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and 

Table A.2).

o A staff approved alternative.

• Nickel Alloys

o Those provided in NUREG/CR-6909 (Ref. 21), using the fatigue design curve 

for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and 

Table A.2).

o A staff approved alternative.

Any one option may be used for calculating the CUFen for each material.

4.3.3.1.4 Potential Fatigue Assessments for BWR Vessel Internals Components

The review procedures in Subsection 4.3.3.1.1 of this review plan section apply.

4.3.3.1.5 Potential Flaw Growth and Fracture Mechanics Analysis

Depending on the choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), the review procedures are 

discussed in the following sub-sections.

4.3.3.1.5.1 10 CFR 54.21(c)(1)(i)

The operating cyclic experience and a list of the assumed cycles used in the existing analyses 

are reviewed to ensure that the number of assumed cycles would not be exceeded during the 

period of extended operation.

4.3.3.1.5.2 10 CFR 54.21(c)(1)(ii)

The staff reviews the applicant’s basis for projecting the amount of flaw growth or increase in 

the stress intensity factor value to the end of the period of extended operation. The staff ensures 

that the applicant’s basis is valid and that the newly-projected values are compared to the 

acceptance criteria for these parameters that were set in the original analysis.

4.3.3.1.5.3 10 CFR 54.21(c)(1)(iii)

The staff reviews the applicant’s proposed program to ensure that the effects of aging on the 

intended function(s) of the subject component will be adequately managed for the period of 

extended operation. The acceptance criteria under 10 CFR 54.21(c)(1)(iii) will be evaluated on a 

case-by-case basis. Chapter X.M1 in the GALL Report may not be used as a basis for 

accepting fatigue-based flaw growth analyses or fracture mechanics analyses in accordance 

with 10 CFR 54.21(c)(1)(iii).

4.3.3.2 FSAR 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. 
December 2010 4.3-11 NUREG-1800, Rev. 2

Table 4.3-2 contains examples of acceptable FSAR supplement information for this TLAA. The 

reviewer verifies that the applicant has provided a FSAR supplement with information equivalent 

to that in Table 4.3-2. 

The 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.

As noted in Table 4.3-2, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should verify that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before the period of extended operation. The 

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 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 staff’s safety evaluation report:

On the basis of its review, as discussed above, the staff concludes that the 

applicant has provided an acceptable demonstration, pursuant to 10 CFR 

54.21(c)(1), that, for the metal fatigue TLAA, [choose which is appropriate] (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. The staff also concludes that the FSAR Supplement 

contains an appropriate summary description of the metal fatigue TLAA 

evaluation for the period of extended operation as reflected in the license 

condition.

4.3.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein will be used by the staff in its evaluation of conformance with NRC 

regulations.

4.3.6 References

1. ASME Section III, “Rules for Construction of Nuclear Power Plant Components,” The ASME 

Boiler and Pressure Vessel Code, 2004 edition, The American Society of Mechanical 

Engineers, New York, NY.

2. ANSI/ASME B31.1, “Power Piping,” American National Standards Institute.
NUREG-1800, Rev. 2 4.3-12 December 2010

3. ANSI/ASME B31.7-1969, “Nuclear Power Piping,” American National Standards Institute.

4. SECY-93-049, “Implementation of 10 CFR Part 54, ‘Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants,’” March 1, 1993.

5. Staff Requirements Memorandum from Samuel J. Chilk, dated June 28, 1993.

6. NUREG-0933, “Resolution of Generic Safety Issues,” Supplement 32, U.S. Nuclear 

Regulatory Commission, August 2008.

7. Letter from William T. Russell of NRC to William Rasin of the Nuclear Management and 

Resources Council, dated July 30, 1993.

8. SECY-94-191, “Fatigue Design of Metal Components,” July 26, 1994.

9. SECY-95-245, “Completion of the Fatigue Action Plan,” September 25, 1995.

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

Nuclear Power Plant Components,” March 1995.

11. Letter from Ashok C. Thadani of the Office of Nuclear Regulatory Research to William D. 

Travers, Executive Director of Operations, dated December 26, 1999.

12. NUREG/CR-6674, “Fatigue Analysis of Components for 60-Year Plant Life,” June 2000.

13. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

14. NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Design Curves of 

Carbon and Low–Alloy Steels,” March 1998.

15. NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of 

Austenitic Stainless Steels,” April 1999.

16. NRC Acceptance for Referencing of BWR Vessel and Internals Project, BWR Core Spray 

Internals Inspection and Flaw Evaluation Guidelines for Compliance with the License 

Renewal Rule (10CFR Part 54), Dec. 7, 2000, in BWRVIP-18-A, “BWR Vessel and Internals 

Project BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines,” EPRI TR1011469, February 2005.

17. NRC Acceptance for Referencing of Report, “BWR Vessel and Internals Project, BWR 

Standby Liquid Control System/Core Plate ΔP Inspection and Flaw Evaluation Guidelines,” 

for Compliance with the License Renewal Rule (10CFR Part 54), Dec. 20, 1999, in 

BWRVIP-27-A, “BWR Vessel and Internals Project BWR Standby Liquid Control 

System/Core Plate P Inspection and Flaw Evaluation Guidelines,” EPRI TR-1007279, 

August 2003.

18. NRC Acceptance for Referencing of Report, “BWR Vessel and Internals Project, BWR 

Lower Plenum Inspection and Flaw Evaluation Guidelines,” for Compliance with the License 

Renewal Rule (10CFR Part 54), Dec. 7, 2000, in BWRVIP-47-A, “BWR Vessel and Internals 
December 2010 4.3-13 NUREG-1800, Rev. 2

Project BWR Lower Plenum Inspection and Flaw Evaluation Guidelines,” EPRI TR-1009947, 

June 2004.

19. NRC Acceptance for Referencing of EPRI Proprietary Report TR-113596, “BWR Vessel and 

Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines,” and Appendix A, “Demonstration of Compliance with the Technical Information 

Requirements of the License Renewal Rule (10CFR 54.21),” Oct. 18, 2001, in BWRVIP-74-

A, “BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection and Flaw 

Evaluation Guidelines,” EPRI TR-1008872, June 2003.

20. Regulatory Guide RG-1.207, “Guidelines for Evaluating Fatigue Analyses Incorporating the 

Life Reduction of Metal Components due to the Effects of the Light-Water Reactor 

Environment for New Reactors,” U.S. Nuclear Regulatory Commission, Washington, DC, 

March 2007.

21. NUREG/CR-6909, “Effect of LWR Coolant Environments on Fatigue Life of Reactor 

Materials” (Final Report), February 2007.
NUREG-1800, Rev. 2 4.3-14 December 2010

Table 4.3-1 Stress Range Reduction Factors

Number of Equivalent 

Full Temperature Cycles

Stress Range 

Reduction Factor

7,000 and less 1.0

7,000 to 14,000 0.9

14,000 to 22,000 0.8

22,000 to 45,000 0.7

45,000 to 100,000 0.6

100,000 and over 0.5

Table 4.3-2 Example of FSAR Supplement for Metal Fatigue TLAA Evaluation

10 CFR 54.21(c)(1)(iii) Example

TLAA

Description

of Evaluation

Implementation 

Schedule*

Metal fatigue The aging management program monitors and tracks the number 

of critical thermal and pressure test transients and monitors the 

cycles for the selected reactor coolant system components.

The aging management program addresses the effects of the 

coolant environment on component fatigue life by assessing the 

impact of the reactor coolant environment on a sample of critical 

components that include, as a minimum, those components 

selected in NUREG/CR-6260. Environmental effects on fatigue for 

these critical components can be evaluated using one of the 

following sets of formulae: 

• Carbon and Low Alloy Steels

o Those provided in NUREG/CR-6583 (Ref. 14), using 

the applicable ASME Section III fatigue design curve.

o Those provided in Appendix A of NUREG/CR-6909 

(Ref. 21), using either the applicable ASME Section III 

fatigue design curve or the fatigue design curve for 

carbon and low alloy steel provided in NUREG/CR-6909 

(Figures A.1 and A.2, respectively, and Table A.1).

o A staff approved alternative.

• Austenitic Stainless Steels

o Those provided in NUREG/CR-5704 (Ref. 15), using 

the applicable ASME Section III fatigue design curve.

o Those provided in NUREG/CR-6909 (Ref. 21), using 

the fatigue design curve for austenitic stainless steel 

provided in NUREG/CR-6909 (Figure A.3 and Table 

A.2).

o A staff approved alternative. 

Evaluation should 

be completed 

before the period 

of extended 

operation
December 2010 4.3-15 NUREG-1800, Rev. 2

Table 4.3-2 Example of FSAR Supplement for Metal Fatigue TLAA Evaluation

10 CFR 54.21(c)(1)(iii) Example

TLAA

Description

of Evaluation

Implementation 

Schedule*

• Nickel Alloys

o Those provided in NUREG/CR-6909 (Ref. 21), using 

the fatigue design curve for austenitic stainless steel 

provided in NUREG/CR-6909 (Figure A.3 and Table 

A.2).

o A staff approved alternative.

Any one option may be used for calculating the CUFen for each 

material.

* An applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer 

should verify that the applicant has identified and committed in the license renewal application to any 

future aging management activities to be completed before the period of extended operation. The staff 

expects to impose a license condition on any renewed license to ensure that the applicant will 

complete these activities no later than the commitment date.

December 2010 4.4-1 NUREG-1800, Rev. 2

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 NRC has established environmental qualification requirements in 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, in its end-of-life condition, will 

meet its performance specifications during and following design basis accidents under the most 

severe environmental conditions postulated at the equipment’s location after such an accident. 

Such conditions include, among others, conditions resulting from loss of coolant accidents 

(LOCAs), high energy line breaks (HELBs), and post-LOCA radiation. Equipment qualified by 

test must be preconditioned by aging to its end-of-life condition (i.e., the condition at the end of 

the current operating term). Those components with a qualified life equal to or greater than the 

duration of the current operating term are covered by TLAAs.

In a related subject, 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 SRP-LR 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 components such as seals, gaskets, 

lubricants, fluids for hydraulic systems, or diaphragms.

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. 10 CFR 50.49 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. 10 CFR 50.49(e)(5) contains provisions 

for aging that require, in part, consideration of all significant types of aging degradation that can 

affect component functional capability. 10 CFR 50.49(e) also requires component replacement 

or refurbishment prior to the end of designated life, unless additional life is established through 

ongoing qualification. 10 CFR 50.49(f) establishes four methods of demonstrating qualification 

for aging and accident conditions. 10 CFR 50.49(k) and (l) permit different qualification criteria 

to apply based on plant and component vintage. Supplemental environmental qualification 

regulatory guidance for compliance with these different qualification criteria is provided in NRC 

RG 1.89, Rev. 1, “Environmental Qualification of Certain Electric Equipment Important to Safety 

for Nuclear Power Plants” (Ref. 1), the Division of Operating Reactors (DOR) Guidelines 

(Ref. 2), and NUREG-0588 (Ref. 3). The principal nuclear industry qualification standards for 

electric equipment are IEEE STD 323-1971 (Ref. 4) and IEEE STD 323-1974 (Ref. 5). These 

standards contain explicit environmental qualification considerations based on TLAAs. 

Compliance with 10 CFR 50.49 provides reasonable assurance that the component can perform 
NUREG-1800, Rev. 2 4.4-2 December 2010

its intended functions during accident conditions after experiencing the effects of inservice 

aging. 

4.4.1.1.1 DOR 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 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.

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 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).

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 period of extended operation to assess the validity of the extended 

qualification.

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 GSI-168, "Environmental Qualification 

of Electrical Equipment" (Ref. 9). This RIS requires no action on the part of the addressees.

4.4.1.3 FSAR Supplement

The detailed information on the evaluation of TLAAs is contained in the renewal application. A 

summary description of the evaluation of TLAAs for the period of extended operation is 

contained in the applicant’s 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

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 extended period of operation, or
December 2010 4.4-3 NUREG-1800, Rev. 2

(iii) the effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

Specific acceptance criteria for environmental qualification 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:

4.4.2.1.1 10 CFR 54.21(c)(1)(i)

The existing qualification is based on previous testing, analysis, or operating experience, 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 renewal

application for the component remains valid for the 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 period of extended operation by testing, 

analysis, or operating experience, or combinations thereof, in accordance with the current 

licensing basis. For option (ii), a reanalysis of the aging evaluation is performed in order to 

project the qualification of the component through the 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 GALL Report (Ref. 10), the staff has evaluated the environmental 

qualification program (10 CFR 50.49) and determined that it is an acceptable aging 

management program to address environmental qualification according to 10 CFR 

54.21(c)(1)(iii). The GALL Report may be referenced in a license renewal application and should 

be treated in the same manner as an approved topical report. However, the GALL Report 

contains one acceptable way and is not the only way to manage aging for license renewal.

In referencing the GALL 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 Report for the generic program apply 

to the applicant’s program.

4.4.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended 

operation in the FSAR supplement is appropriate such that later changes can be 

controlled by 10 CFR 50.59. The description should contain information 

associated with the TLAA regarding the basis for determining that the applicant 

has made the demonstration required by 10 CFR 54.21(c)(1).
NUREG-1800, Rev. 2 4.4-4 December 2010

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, 

depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:

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, are reviewed to 

confirm that the original qualified life remains valid for the 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 period of extended operation are 

reviewed. The qualification methods include testing, analysis, operating experience, or 

combinations thereof.

The reanalysis of an aging evaluation is normally performed to extend the qualification by 

reducing excess conservatisms incorporated in the prior evaluation. Such a reanalysis is 

performed on a routine basis as part of an environmental qualification program. A component 

life-limiting condition may be due to thermal, radiation, or cyclical aging; the vast majority of 

component aging limits are based on thermal conditions. Conservatisms may exist in aging 

evaluation parameters, such as the assumed ambient temperature of the component, 

unrealistically low activation energy, or in the application of a component (de-energized versus 

energized). The reanalysis of an aging evaluation is documented in accordance with the plant’s 

quality assurance program, which provides for the verification of assumptions and conclusions. 

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 Report in its license renewal application, as appropriate. 

The review should verify that the applicant has stated that the report is applicable to its plant 

with respect to its environmental qualification program. The reviewer verifies that the applicant 

has identified the appropriate program as described and evaluated in the GALL Report. The 

reviewer also ensures that the applicant has stated that its environmental qualification program 

contains the same program elements that the staff evaluated and relied upon in approving the 

corresponding generic program in the GALL Report. No further staff evaluation is necessary.

If the applicant does not reference the GALL Report in its renewal application, additional staff 

evaluation is necessary to determine whether the applicant’s program is acceptable for this area 

of review.
December 2010 4.4-5 NUREG-1800, Rev. 2

4.4.3.2 FSAR 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 environmental 

qualification of 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 equivalent to that in Table 4.4-2. 

The 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. The staff will review any such changes when the next update is 

submitted. If the applicant updates the FSAR to include the final FSAR supplement before the 

license is renewed, no condition will be necessary. 

As noted in Table 4.4-2, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should verify that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before the period of extended operation. The 

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 of Findings

The reviewer determines whether the applicant has provided information sufficient to satisfy the 

provisions of this section and whether the 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 staff’s safety evaluation report:

On the basis of its review, as discussed above, the 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 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. The 

staff also concludes that the FSAR supplement contains an appropriate summary 

description of the environmental qualification of electric equipment TLAA 

evaluation for the period of extended operation as reflected in the license 

condition.

4.4.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method for 

complying with specific portions of the NRC’s regulations, the method described herein will be 

used by the staff in its evaluation of conformance with NRC regulations.
NUREG-1800, Rev. 2 4.4-6 December 2010

4.4.6 References

1. Regulatory Guide 1.89, Rev. 1, “Environmental Qualification of Certain Electric Equipment 

Important to Safety for Nuclear Power Plants,” June 1984.

2. “Guidelines for Evaluating Environmental Qualification of Class 1E Electrical Equipment in 

Operating Reactors,” (DOR Guidelines), November 1979.

3. NUREG-0588, “Interim Staff Position on Environmental Qualification of Safety-Related 

Equipment,” July 1981. 

4. IEEE STD 323-1971, “IEEE Trial Use Standard; General Guide for Qualifying Class 1E 

Equipment for Nuclear Power Generating Stations.” 

5. IEEE STD 323-1974, “IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power 

Generating Stations.”

6. IEEE STD 382-1972, “Standard for Qualification of Actuators for Power Operated Valve 

Assemblies with Safety Related Functions for Nuclear Power Plants.”

7. IEEE STD 334-1971, “IEEE Standard for Type Tests of Continuous Duty Class 1E Motors 

for Nuclear Power Generating Stations.”

8. NRC Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

Instrumentation and Control Cables,” May 2, 2003.

9. Generic Safety Issue -168, “Environmental Qualification of Low-Voltage Instrumentation and 

Control Cables,” February 2001. 

10. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.
December 2010 4.4-7 NUREG-1800, Rev. 2

Table 4.4-1 Environmental Qualification Reanalysis Attributes

Reanalysis 

Attributes Description

Analytical 

methods

The analytical models used in the reanalysis of an aging evaluation should 

be 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 license renewal, one acceptable method of establishing the 60-

year normal radiation dose is to multiply the 40-year normal radiation dose by 

1.5 (i.e., 60 years/40 years). The result is added to the accident radiation 

dose to obtain the total integrated dose for the component. For cyclical aging, 

a similar approach may be used. Other models may be justified on a caseby-case basis.

Data 

collection and 

reduction 

methods

Reducing excess conservatisms in the component service conditions (for 

example, temperature, radiation, cycles) used in the prior aging evaluation is 

the chief method used for a reanalysis. Temperature data used in an aging 

evaluation should be conservative and based on plant design temperatures 

or on actual plant temperature data. When used, plant temperature data can 

be obtained in several ways, including monitors used for technical 

specification compliance, other installed monitors, measurements made by 

plant operators during rounds, and temperature sensors on large motors 

(while the motor is not running). A representative number of temperature 

measurements are conservatively evaluated to establish the temperatures 

used in an aging evaluation. Plant temperature data may be used in an aging 

evaluation in different ways, such as (a) directly applying the plant 

temperature data in the evaluation or (b) using the plant temperature data to 

demonstrate conservatism when using plant design temperatures for an 

evaluation. Any changes to material activation energy values as part of a 

reanalysis should be justified. Similar methods of reducing excess 

conservatisms in the component service conditions used in prior aging 

evaluations can be used for radiation and cyclical aging.

Underlying 

assumptions

Environmental qualification component aging evaluations contain sufficient 

conservatisms to account for most environmental changes occurring due to 

plant modifications and events. When unexpected adverse conditions are 

identified during operational or maintenance activities that affect the 

environment of a qualified component, the affected environmental 

qualification component is evaluated and appropriate corrective actions are 

taken, which may include changes to the qualification bases and 

conclusions.

Acceptance 

criteria and 

corrective 

actions

The reanalysis of an aging evaluation should extend the qualification of the 

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 unsuccessful).
NUREG-1800, Rev. 2 4.4-8 December 2010

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

Equipment TLAA Evaluation

10 CFR 54.21(c)(1)(i) Example

TLAA Description of Evaluation Implementation 

Schedule*

Environmental 

qualification of 

electric equipment

The original environmental qualification qualified 

life has been shown to remain valid for the period 

of extended operation.

Completed

10 CFR 54.21(c)(1)(ii) Example

TLAA Description of Evaluation Implementation 

Schedule*

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.

Completed

10 CFR 54.21(c)(1)(iii) Example

TLAA Description of Evaluation Implementation 

Schedule*

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 period of 

extended operation because equipment will be 

replaced prior to reaching the end of its qualified 

life. Reanalysis addresses attributes of analytical 

methods, data collection and reduction methods, 

underlying assumptions, acceptance criteria, 

corrective actions if acceptance criteria are not 

met, and the period of time prior to the end of 

qualified life when the reanalysis will be 

completed.

Existing program

* An applicant need not incorporate the implementation schedule into its FSAR. However, the 

reviewer should verify that the applicant has identified and committed in the license renewal 

application to any future aging management activities to be completed before the period of 

extended operation. The 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.
December 2010 4.5-1 NUREG-1800, Rev. 2

4.5 CONCRETE CONTAINMENT TENDON PRESTRESS ANALYSIS

Review Responsibilities

Primary - Branch responsible for TLAA issues

Secondary - Branch responsible for structural engineering 

4.5.1 Areas of Review

The prestressing tendons in prestressed concrete containments lose their prestressing forces 

with time due to creep and shrinkage of concrete and relaxation of the prestressing steel. During 

the design phase, engineers estimate these losses to arrive at the end of operating life (Refs. 1 

and 2), normally 40 years. The operating experiences with the trend of prestressing forces 

indicate that the prestressing tendons lose their prestressing forces at a rate higher than 

predicted due to sustained high temperature (Ref. 3). Thus, it is necessary to ensure that the 

applicant addresses existing TLAAs for the extended period of operation.

The adequacy of the prestressing forces in prestressed concrete containments is reviewed for 

the 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 NRC’s regulations in 10 CFR 

54.21(c)(1).

4.5.2.1 Time-Limited Aging Analysis

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 extended period of operation; or

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

Accordingly, the specific options for satisfying the acceptance criterion are: 

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 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 period of extended 

operation.
NUREG-1800, Rev. 2 4.5-2 December 2010

4.5.2.1.2 10 CFR 54.21(c)(1)(ii)

The trend line of prestressing forces for each group of tendons developed for 40 years of 

operation should be extended to 60 years. The applicant should demonstrate that the trend lines 

of the measured prestressing forces will stay above the design Minimum Required Value (MRV) 

in the CLB for each group of tendons during the period of extended operation (Ref. 4). If this 

cannot be done, the applicant should develop a systematic plan for retensioning selected 

tendons so that the trend lines will remain above the minimum required prestress force specified 

at anchorages for each group of tendons during the period of extended operation, or perform a 

reanalysis of containment to demonstrate design adequacy.

4.5.2.1.3 10 CFR 54.21(c)(1)(iii)

In Chapter X of the GALL Report (Ref. 4), the staff evaluated a program that assesses the 

concrete containment tendon prestressing forces, and has determined that it is an acceptable 

aging management program to address concrete containment tendon prestress according to 

10 CFR 54.21(c)(1)(iii), except for operating experience. The GALL Report recommends further 

evaluation of the applicant’s operating experience related to the containment prestress force. 

However, the GALL report contains one acceptable way and not the only way to manage aging 

for license renewal.

The GALL report may be referenced in a license renewal application, and is treated in the same 

manner as an approved topical report. However, the GALL report contains one acceptable way, 

but not the only way, to manage aging for license renewal.

In referencing the GALL 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 report for the generic program apply to the applicant’s 

program.

4.5.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended operation in the 

FSAR supplement is appropriate such that later changes can be controlled by 10 CFR 50.59. 

The description must contain information associated with the TLAAs regarding the basis for 

determining that the applicant has made the demonstration required by 10 CFR 54.21(c)(1).

4.5.3 Review Procedures

For each area of review described in Subsection 4.5.1, the following review procedures should 

be followed:

4.5.3.1 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:
December 2010 4.5-3 NUREG-1800, Rev. 2

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 will cover the 

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 tendon group) are 

considered in the regression analysis, as discussed in IN 99-10 (Ref. 3). Either the reviewer 

verifies that the trend lines will stay above the minimum required prestressing forces for each 

group of tendons during the period of extended operation or, if the trend lines fall below the 

minimum required prestressing forces during this period, the reviewer verifies that the applicant 

has a systematic plan for retensioning the tendons to ensure that the trend lines will return to 

being, and remain, above the minimum required prestressing forces for each group of tendons 

during the period of extended operation. If the applicant chooses to reanalyze the containment, 

the reviewer verifies that the design adequacy is maintained in the period of extended operation.

4.5.3.1.3 10 CFR 54.21(c)(1)(iii)

An applicant may reference the GALL Report in its license renewal application, 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 Chapter 

X.S1) as described and evaluated in the GALL Report. The reviewer also ensures that the 

applicant has stated that its program contains the same program elements that the staff 

evaluated and relied upon in approving the corresponding generic program in the GALL Report.

The GALL Report recommends further evaluation of the applicant’s operating experience 

related to the containment prestress force. The applicant’s program should incorporate the 

relevant operating experience 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 Information Notice 99-10 (Ref. 3). Tendon operating experience 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 (PWR or BWR). The reviewer reviews the applicant’s program to verify that the 

applicant has adequately considered plant-specific operating experience.

If the applicant does not reference the GALL Report in its renewal application, additional 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 

SRP-LR to ensure that loss of prestress in the concrete containment prestressing tendons is 

adequately managed for the period of extended operation. 

4.5.3.2 FSAR 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 tendon prestress TLAA. 
NUREG-1800, Rev. 2 4.5-4 December 2010

Table 4.5-1 contains examples of acceptable FSAR supplement information for this TLAA. The 

reviewer verifies that the applicant has provided a FSAR supplement with information equivalent 

to that in Table 4.5-1. 

The 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.

As noted in Table 4.5-1, an applicant need not incorporate the implementation schedule into its 

FSAR. However, the reviewer should verify that the applicant has identified and committed in 

the license renewal application to any future aging management activities, including 

enhancements and commitments to be completed before the period of extended operation. The 

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 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 staff’s safety evaluation report:

On the basis of its review, as discussed above, the 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 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. The staff also 

concludes that the FSAR supplement contains an appropriate description of the 

concrete containment tendon prestress TLAA evaluation for the period of 

extended operation as reflected in the license condition.

4.5.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein will be used by the staff in its evaluation of conformance with NRC 

regulations.

4.5.6 References

1. Regulatory Guide 1.35, Rev. 3, “Inspection of Ungrouted Tendons in Prestressed Concrete 

Containments,” July 1990.

2. Regulatory Guide 1.35.1, “Determining Prestressing Forces for Inspection of Prestressed 

Concrete Containments,” July 1990.
December 2010 4.5-5 NUREG-1800, Rev. 2

3. NRC Information Notice 99-10, “Degradation of Prestressing Tendon Systems in 

Prestressed Concrete Containments,” April 1999.

4. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.
NUREG-1800, Rev. 2 4.5-6 December 2010 

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 

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 evaluation has been determined 

to remain valid to the end of the 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 

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 aging management program developed to monitor 

the prestressing forces should ensure that, during each 

inspection, the trend lines of the measured prestressing 

forces show that they meet the requirements of 10 CFR 

50.55a(b)(2)(viii)(B). If the trend lines cross the PLLs, 

corrective actions will be taken. The program will also 

incorporate any plant-specific and industry operating 

experience. 

Program should 

be implemented 

before the period 

of extended 

operation. 

* An applicant need not incorporate the implementation schedule into its FSAR. However, 

the reviewer should verify that the applicant has identified and committed in the license 

renewal application to any future aging management activities to be completed before the 

period of extended operation. The 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. 
December 2010 4.6-1 NUREG-1800, Rev. 2

4.6 CONTAINMENT LINER PLATE, METAL CONTAINMENTS, AND PENETRATIONS 

FATIGUE ANALYSIS

Review Responsibilities

Primary - Branch responsible for mechanical engineering

Secondary - Branch responsible for structural engineering

4.6.1 Areas of Review

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 10 CFR Part 50. The thickness of the liner plates is generally between 1/4 inch 

(6.2 millimeter) and 3/8-inch (9.5 millimeter). 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, normal loads, such as from concrete 

shrinkage, creep, and thermal changes, imposed on the concrete containment structure, are 

transferred to the liner plates through the anchorage system. Internal pressure and temperature 

loads are directly applied to the liner plates. Thus, under design-basis conditions, the liner 

plates could experience significant strains. Some plants may have metal containments instead 

of concrete containments with liner plates. The metal containments are designed to carry gravity 

and seismic loads in addition to the internal pressure and temperature loads. Additionally, the 

BWR containment suppression pool chamber 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 liner plates or metal containments may be considered in the design based on an 

assumed number of loading cycles for the current operating term. The cyclic loads include 

reactor building interior temperature variation during the heatup and cooldown of the reactor 

coolant system, a LOCA, 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” (Ref. 1). 

High energy piping penetrations and the fuel transfer tubes in some plants are equipped with 

stainless steel bellow assemblies. These are designed to accommodate relative movements 

between the containment wall (including the liner) and the adjoining structures. The penetrations 

have sleeves (up to 10 feet in length, with a 2- to 3-inch annulus around the piping) to penetrate 

the concrete containment wall and allow movement of the piping system. Dissimilar metal welds 

connect the piping penetrations to the bellows or stainless steel plates to provide essentially 

leak-tight penetrations.

The containment liner plates, metal containments, BWR containment suppression chamber and 

the vent system, penetration sleeves (including dissimilar metal welds), and penetration bellows 

may be designed in accordance with requirements of Section III of the ASME Boiler and 

Pressure Vessel Code. If a plant’s code of record requires a fatigue analysis, then this analysis 

may be a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1) to ensure that 
NUREG-1800, Rev. 2 4.6-2 December 2010

the effects of aging on the intended functions are adequately managed for the period of 

extended operation.

The adequacy of the fatigue analyses of the containment liner plates (including welded joints), 

metal containments, BWR containment suppression chamber and the vent system, penetration 

sleeves, dissimilar metal welds, and penetration bellows is reviewed in this section for the 

period of extended operation. The fatigue analyses of the pressure boundary of process piping 

are reviewed separately following the guidance in SRP-LR Section 4.3, “Metal Fatigue.”

4.6.1.1 Time-Limited Aging Analysis

The containment liner plates (including welded joints), metal containments, BWR containment 

suppression chamber and the vent system, penetration sleeves, dissimilar metal welds, and 

penetration bellows may be designed and/or analyzed in accordance with ASME code 

requirements. The ASME code contains explicit metal fatigue or cyclic considerations based on 

TLAAs. Specific requirements are contained in the design code of reference for each plant.

4.6.1.1.1 ASME Section III, MC or Class 1

ASME Section III, Division 2, “Code for Concrete Reactor Vessel and Containments,” 

Subsection CC, “Concrete Containment,” and Division 1, Subsection NE, “Class MC 

Components,” (Ref. 2) 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 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 period of extended operation is an area of review.

4.6.1.1.2 Other Evaluations Based on CUF

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). For these cases, 

the discussion relating to ASME Section III, MC or Class 1, in Subsection 4.6.1.1.1 applies.

4.6.1.2 FSAR Supplement

Detailed information on the evaluation of TLAAs is contained in the renewal application. A 

summary description of the evaluation of TLAAs for the period of extended operation is 

contained in the applicant’s 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 NRC’s regulations in 10 CFR 

54.21(c)(1).

4.6.2.1 Time-Limited Aging Analysis

Pursuant to 10 CFR 54.21(c)(1), an applicant must demonstrate one of the following:
December 2010 4.6-3 NUREG-1800, Rev. 2

(i) The analyses remain valid for the period of extended operation;

(ii) The analyses have been projected to the end of the extended period of operation; or

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

Specific acceptance criteria for fatigue of containment liner plates, metal containments, liner 

plate weld joints, dissimilar metal welds, penetration sleeves, and penetration bellows are:

4.6.2.1.1 ASME Section III, MC or Class 1

For containment liner plates, metal containments, BWR containment suppression chamber and 

the vent system, and penetrations designed or analyzed to ASME MC or Class 1 requirements, 

the acceptance criteria, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), 

are:

4.6.2.1.1.1 10 CFR 54.21(c)(1)(i)

The existing CUF calculations remain valid because the number of assumed cyclic loads will not 

be exceeded during the period of extended operation.

4.6.2.1.1.2 10 CFR 54.21(c)(1)(ii)

CLB fatigue analysis, per ASME Code Section III, was conducted for a 40-year life. The CUF 

calculations are re-evaluated based on an increased number of assumed cyclic loads to cover 

the period of extended operation. All cyclic loads considered in the original fatigue analyses 

(including Type A and Type B leak rate tests) are re-evaluated and revised, as necessary. The 

revised analysis shows that the CUF does not exceed one, as required by the ASME code, 

during the period of extended operation. 

4.6.2.1.1.3 10 CFR 54.21(c)(1)(iii)

An aging management program provided by the applicant shall demonstrate that the effects of 

aging on the component's intended function(s) will be adequately managed during the period of 

extended operation. If the proposed aging management program relies on mitigation or 

inspection, it shall be evaluated against the 10 elements described in Branch Technical Position 

RLSB-1 (Appendix A.1 of this standard review plan). However, if the component is replaced, the 

CUF for the replacement must be less than or equal to one during the period of extended 

operation.

4.6.2.1.2 Other Evaluations Based on CUF

The acceptance criteria in Subsection 4.6.2 apply. 

4.6.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended 

operation in the FSAR supplement is appropriate such that later changes can be 

controlled by 10 CFR 50.59. The description should contain information associated with 
NUREG-1800, Rev. 2 4.6-4 December 2010

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 following review procedures is 

followed:

4.6.3.1 Time-Limited Aging Analysis

4.6.3.1.1 ASME Section III, MC or Class 1

For containment liner plates, metal containments, BWR containment suppression chamber and 

the vent system, and penetrations designed or analyzed to ASME MC or Class 1 requirements, 

the review procedures, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), 

are:

4.6.3.1.1.1 10 CFR 54.21(c)(1)(i)

The number of assumed transients used in the existing CUF calculations for the current 

operating term is compared to the extrapolation to 60 years of operation of the number of 

operating transients experienced to date. The comparison confirms that the number of 

transients in the existing analyses will not be exceeded during the period of extended operation.

4.6.3.1.1.2 10 CFR 54.21(c)(1)(ii)

Operating transient experience and a list of the increased number of assumed cyclic loads 

projected to the end of the period of extended operation are reviewed to ensure that the cyclic 

load projection is adequate. The revised CUF calculations based on the projected number of 

assumed cyclic loads are reviewed to ensure that the CUF remains less than one at the end of 

the period of extended operation.

The 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.

4.6.3.1.1.3 10 CFR 54.21(c)(1)(iii)

The applicant’s proposed aging management program to ensure that the effects of aging on the 

intended function(s) are adequately managed for the period of extended operation is reviewed. 

If the program relies on mitigation or inspection, it shall be reviewed against the 10 elements 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this standard review plan). If 

the applicant proposes a component replacement before its CUF exceeds one, the reviewer 

verifies that the CUF for the replacement will remain less than or equal to one during the period 

of extended operation.

Applicant-proposed programs are reviewed on a case-by-case basis.

4.6.3.1.2 Other Evaluations Based on CUF

The review procedures in Subsection 4.6.3.1 apply.
December 2010 4.6-5 NUREG-1800, Rev. 2

4.6.3.2 FSAR 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 containment liner plate, 

metal containments, BWR containment suppression chamber and the vent system, and 

penetrations fatigue TLAA. 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 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.

As noted in Table 4.6-1, the applicant need not incorporate the implementation schedule into its 

FSAR. However, the review should verify that the applicant has identified and committed in the 

license renewal application to any future aging management activities, including enhancements 

and commitments to be completed before the period of extended operation. The 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 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 staff’s safety 

evaluation report:

On the basis of its review, as discussed above, the staff concludes that the 

applicant has provided an acceptable demonstration, pursuant to 10 CFR 

54.21(c)(1), that the containment liner plate or metal containment, BWR 

containment suppression chamber and the vent system, and penetrations fatigue 

TLAA, [choose which is appropriate] (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. The 

staff also concludes that the FSAR supplement contains an appropriate summary 

description of the containment liner plate or metal containment, BWR 

containment suppression chamber and the vent system, and penetrations fatigue 

TLAA evaluation for the period of extended operation as reflected in the license 

condition.

4.6.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein will be used by the staff in its evaluation of conformance with NRC 

regulations.
NUREG-1800, Rev. 2 4.6-6 December 2010

4.6.6 References

1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” U.S. Nuclear Regulatory Commission, March 2007.

2. ASME Section III, Division 2, “Code for Concrete Reactor Vessels and Containments,” 

Subsection CC, “Concrete Containment,” and Division 1, Subsection NE, “MC Components,” 

The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, 

The American Society of Mechanical Engineers, New York, NY.
December 2010 4.6-7 NUREG-1800, Rev. 2

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 

(or metal 

containment) 

and 

penetrations 

fatigue

The containment liner plates (or metal containment), 

BWR containment suppression chamber and the vent 

system, liner weld joints, penetration sleeves, dissimilar 

metal welds, and penetration bellows that provide an 

essentially leak-tight barrier. A Section III, MC or Class 1 

fatigue analysis limits the CUF to a value less than or 

equal to one for acceptable fatigue design. The existing 

CUF evaluation has been determined to remain valid 

because the number of assumed cyclic loads would not 

be exceeded during the period of extended operation.

Completed

10 CFR 54.21(c)(1)(ii) Example

TLAA Description of Evaluation Implementation

Schedule*

Containment 

liner plates 

(or metal 

containment) 

and 

penetrations 

fatigue

The containment liner plates (or metal containment), 

BWR containment suppression chamber and the vent 

system, liner weld joints, penetration sleeves, dissimilar 

metal welds, and penetration bellows that provide an 

essentially leak-tight barrier. A Section III, MC or Class 

1 fatigue analysis limits the CUF to a value less than or 

equal to one for acceptable fatigue design. The CUF 

calculations have been reevaluated based on an 

increased number of assumed cyclic loads to cover the 

period of extended operation. The revised CUF will not 

exceed one during the period of extended operation.

Completed

10 CFR 54.21(c)(1)(iii) Example

TLAA Description of Evaluation Implementation

Schedule*

Containment 

liner plates 

(or metal 

containment) 

and 

penetrations 

fatigue

The containment liner plates (or metal containment), 

BWR containment suppression chamber and the vent 

system, liner weld joints, penetration sleeves, dissimilar 

metal welds, and penetration bellows that provide an 

essentially leak-tight barrier. A Section III, MC or Class 

1 fatigue analysis limits the CUF to a value less than or 

equal to one for acceptable fatigue design. If the 

component is replaced, the CUF for the replacement 

will be shown to be less than one during the period of 

extended operation.

Program should be 

implemented before 

the period of 

extended operation.
NUREG-1800, Rev. 2 4.6-8 December 2010

Note: All containment components need not meet the same requirement. It is likely that the liner 

plate and the bellows may be evaluated per 10CFR54.21(c)(1)(i), while high energy 

penetrations may be evaluated per 10CFR54.21(c)(1)(ii).

* An applicant need not incorporate the implementation schedule into its FSAR. However, the 

reviewer should verify that the applicant has identified and committed in the license renewal 

application to any future aging management activities to be completed before the period of 

extended operation. The 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.
December 2010 4.7-1 NUREG-1800, Rev. 2

4.7 OTHER PLANT-SPECIFIC TIME-LIMITED AGING ANALYSES

Review Responsibilities

Primary - NRR branch responsible for the 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 have been based on an explicitly 

assumed 40-year plant life (for example, aspects of the reactor vessel design) and may, 

therefore, be TLAAs. Pursuant to 10 CFR 54.21(c), a license renewal applicant is required to 

evaluate TLAAs. The definition of TLAAs is provided in 10 CFR 54.3 and in Section 4.1 of this 

SRP-LR.

Plant-specific TLAAs may have evolved since issuance of a plant’s operating license. As 

indicated in 10 CFR 54.30, the adequacy of the plant’s CLB, which includes TLAAs, is not an 

area within the scope of the license renewal 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.

License renewal reviews focus on the 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, or components 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 license renewal 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 staff reviews the applicant’s identification of TLAAs 

and exemptions separately, following the guidance in Section 4.1 of this SRP-LR.

Based on lessons learned in the review of the initial license renewal applications, the staff has 

developed review procedures for the evaluation of certain TLAAs. If an applicant identifies these 

TLAAs as applicable to its plant, the staff reviews them separately, following the guidance in 

Sections 4.2 through 4.6. The reviewer reviews other TLAAs that are identified by the applicant 

following the generic guidance in this section. For particular systems, the reviewers from 

branches responsible for those systems may be requested to assist in the review, as 

appropriate.

The following areas relating to a TLAA are reviewed:

4.7.1.1 Time-Limited Aging Analysis

The evaluation of the TLAA for the period of extended operation is reviewed.
NUREG-1800 Rev. 2 4.7-2 December 2010

4.7.1.2 FSAR Supplement

The FSAR supplement summarizing the evaluation of the TLAA for the period of extended 

operation in accordance with 10 CFR 54.21(d) is reviewed.

4.7.2 Acceptance Criteria

The acceptance criteria for the areas of review described in Subsection 4.7.1 of this section 

delineate acceptable methods for meeting the requirements of the NRC’s regulations in 10 CFR 

54.21(c)(1).

4.7.2.1 Time-Limited Aging Analysis

Pursuant to 10 CFR 54.21(c)(1)(i) - (iii), an applicant must demonstrate one of the following for 

the TLAAs:

(i) The analyses remain valid for the period of extended operation;

(ii) The analyses have been projected to the end of the extended period of operation; or

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

4.7.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:

The summary description of the evaluation of TLAAs for the period of extended operation in the 

FSAR supplement is appropriate 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 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 license renewal is that these analyses may not have properly 

considered the length of the extended period of operation, which may change conclusions with

regard to safety and the capability of SSCs within the scope of the Rule to perform or one or 

more safety functions. The review of these TLAAs provides the assurance that the aging effect 

is properly addressed through the period of extended operation.

For each area of review described in Subsection 4.7.1, the following review procedures are 

followed:

4.7.3.1 Time-Limited Aging Analysis

For each TLAA identified, the review procedures depend on the applicant’s choice of methods 

of compliance from those identified in 10 CFR 54.21(c)(1)(i), (ii), or (iii), as follows:
December 2010 4.7-3 NUREG-1800, Rev. 2

4.7.3.1.1 10 CFR 54.21(c)(1)(i)

Justification provided by the applicant is reviewed to verify that the existing analyses are valid 

for the period of extended operation. The existing analyses should be shown to be bounding 

even during the 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). The applicant shows that (a) conditions and assumptions used in the analysis 

already address the relevant aging effects for the period of extended operation, and 

(b) acceptance criteria are maintained to provide reasonable assurance that the intended 

function(s) is maintained for renewal. Thus, no reanalysis is necessary for renewal.

In some instances, the applicant may identify activities to be performed to verify the assumption 

basis of the calculation, such as cycle counting. An evaluation of that activity is provided by the 

applicant. The reviewer assures that the applicant’s activity is sufficient to confirm the 

calculation assumptions for the 60-year period.

If the TLAA must be modified or recalculated to extend the period of evaluation to consider the 

period of extended operation, the 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 period of extended operation (e.g., 60 

years). The applicable analysis technique can be the one that is in effect in the plant’s CLB at 

the time of filing of the renewal application.

The applicant may recalculate the TLAA using a 60-year period to show that the TLAA 

acceptance criteria continue to be satisfied for the period of extended operation. The applicant 

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 a 

60-year period. The applicant shall provide a sufficient description of the analysis and 

documents the results of the reanalysis to show that it is satisfactory for the 60-year period.

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 identifies activities to be performed to verify the assumption basis 

of the calculation, such as cycle counting. An evaluation of that activity is provided by the 

applicant. The reviewer confirms that the applicant’s activity is sufficient to confirm the 

calculation assumptions for the 60-year period.

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 in the same manner as described in the IPA in 10 CFR 

54.21(a)(3). The reviewer reviews the applicant’s aging management program to verify that the 
NUREG-1800 Rev. 2 4.7-4 December 2010

effects of aging on the intended function(s) are adequately managed consistent with the CLB for 

the period of extended operation.

The applicant identifies the structures and components 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). In cases where a mitigation 

or inspection program is proposed, the reviewer uses the guidance provided in Branch 

Technical Position RLSB-1 of this standard review plan to ensure that the effects of aging on the 

structure- and component-intended function(s) are adequately managed for the period of 

extended operation.

4.7.3.2 FSAR 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 appropriate, such that later changes can be 

controlled by 10 CFR 50.59. The description should contain information that the TLAAs have 

been dispositioned for the period of extended operation. Sections 4.2 through 4.6 of this 

standard review plan contain examples of acceptable FSAR supplement information for TLAA 

evaluation. 

The 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 is necessary.

As noted in Sections 4.2 through 4.6, an applicant need not incorporate the implementation 

schedule into its FSAR. However, the review should verify that the applicant has identified and 

committed in the license renewal application to any future aging management activities, 

including enhancements and commitments to be completed before the period of extended 

operation. The 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.

4.7.4 Evaluation Findings

The reviewer determines whether the applicant has provided sufficient information to satisfy the 

provisions of Section 4.7 and whether the 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 staff’s safety evaluation report:

On the basis of its review, as discussed above, the 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 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. The staff also concludes that the FSAR 
December 2010 4.7-5 NUREG-1800, Rev. 2

supplement contains an appropriate summary description of this TLAA evaluation 

for the period of extended operation as reflected in the license condition.

4.7.5 Implementation

Except in those cases in which the applicant proposes an acceptable alternative method, the 

method described herein is used by the staff in its evaluation of conformance with NRC 

regulations.

4.7.6 References

None

December 2010 A-i NUREG-1800, Rev. 2

APPENDIX A

BRANCH TECHNICAL POSITIONS

December 2010 A.1-1 NUREG-1800, Rev. 2

A.1 AGING MANAGEMENT REVIEW - GENERIC (BRANCH TECHNICAL POSITION 

RLSB-1)

A.1.1 Background

Pursuant to 10 CFR 54.21(a)(3), a license renewal applicant is required to demonstrate that the 

effects of aging on structures and components subject to an Aging Management Review (AMR) 

are adequately managed so their intended functions will be maintained consistent with the CLB 

for the 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.

The license renewal process is not intended to demonstrate absolute assurance that structures 

and components will not fail, but rather that there is reasonable assurance that they will perform 

such that the intended functions are maintained consistent with the current licensing basis 

(CLB) during the period of extended operation.

There are generally four types of aging management programs (AMPS): prevention, mitigation, 

condition monitoring, and 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. Examples are the visual examination of concrete structures for cracking and the 

ultrasonic examination of pipe wall for flow-accelerated corrosion (FAC)-induced wall thinning. 

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.

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 structure and component 

degradation. The materials, environment, stresses, service conditions, operating 

experience, and other relevant information should be considered in identifying applicable 

aging effects. The effects of aging on the intended function(s) of structures and 

components also should be considered.

2. Relevant aging information may be contained in, but is not limited to, the following 

documents: plant-specific maintenance and inspection records; plant-specific site 

deviation or issue reports; plant-specific NRC and Institute of Nuclear Power Operations 

(INPO) inspection reports; plant-specific licensee self-assessment reports; plant-specific 

and other licensee event reports (LERs); NRC, INPO, and vendor generic 

communications; GSIs/unresolved safety issues (USIs); NUREG reports; and Electric 

Power Research Institute (EPRI) reports.
NUREG-1800, Rev. 2 A.1-2 December 2010

3. If operating experience 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 unless the applicant has provided 

the basis for this determination in its license renewal application. However, in 

questioning the absence of the aging effect, a reference and/or basis which aided the 

applicant in addressing the question should be provided. 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 GALL Report is not a 

sufficient basis. For example, the aging effect is applicable to a PWR component, but the 

applicant’s plant is a BWR and does not have such a component. In this example, using 

the GALL Report merely as a checklist is not relevant.

4. An aging effect may not have been identified in the GALL Report, if it arises out of 

industry experience after the issuance of the GALL 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 license renewal even if there is a 

prevention or mitigation program associated with that aging effect. For example, water 

chemistry, a coating, or use of cathodic protection could prevent or mitigate corrosion, 

but corrosion should be identified as applicable for license renewal, and the AMR should 

consider the adequacy of the 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 (IPA).

7. The applicable aging effects to be considered for license renewal include those that 

could result from normal plant operation, including plant/system operating transients and 

plant shutdown. Specific aging effects from abnormal events need not be postulated for 

license renewal. However, if an abnormal event has occurred at a particular plant, its 

contribution to the aging effects on structures and components for license renewal 

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 (LOCA), and safe shutdown earthquake (SSE). 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 license renewal. 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 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 
December 2010 A.1-3 NUREG-1800, Rev. 2

occur, and the leakage could cause corrosion. Thus, the aging effects from leakage of 

bolted connections should be evaluated for license renewal.

An aging effect due to an abnormal event does not preclude that aging effect from 

occurring during normal operation for the 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 license renewal. 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 License Renewal

1. An acceptable AMP should consist of the 10 elements described in Table A.1-1, as 

appropriate (Ref. 1). These program elements/attributes 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 AMPs/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 structures and components subject to an 

AMR, the effects of aging will be adequately managed in the period of extended 

operation. Thus, risk significance may be considered in developing the details of an AMP 

for the structure or component for license renewal, but may not be used to conclude that 

no AMP is necessary for license renewal.

A.1.2.3 Aging Management Program Elements

A.1.2.3.1 Scope of Program

The specific program necessary for license renewal should be identified. The scope of the 

program should include the specific structures and components, 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.
NUREG-1800, Rev. 2 A.1-4 December 2010

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. 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 

other intended function(s) of the tubes, such as pressure boundary. Thus, a performance 

monitoring program must ensure that the structure and components 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 structure- and 

component-intended function(s). The parameters to be monitored or inspected should be 

appropriate to ensure that the structure- and component-intended function(s) will be 

adequately maintained for license renewal under all CLB design conditions. 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 agerelated degradation or an aging effect prior to a loss of structure and component (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 levelintended function(s), including redundancy, diversity, and defense-in-depth consistent 

with the plant’s CLB, would be maintained for license renewal. A program based solely 
December 2010 A.1-5 NUREG-1800, Rev. 2

on detecting structure and component failure should not be considered as an effective 

AMP for license renewal.

3. This program element describes “when,” “where,” and “how” program data are collected 

(i.e., all aspects of activities to collect data as part of the program).

4. 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 industrywide operating experience. The discussion should provide 

justification, including codes and standards referenced, that the technique and frequency 

are adequate to detect the aging effects before a loss of SC-intended function. A 

program based solely on detecting SC failures is not considered an effective AMP.

For a condition monitoring program, when sampling is used to represent a larger 

population of SCs, applicants should provide the basis for the inspection population and 

sample size. The inspection population should be based on such aspects of the SCs as 

a similarity of materials of construction, fabrication, procurement, design, installation, 

operating environment, or aging effects. The sample size should be based on such 

aspects of the SCs as the specific aging effect, location, existing technical information, 

system and structure design, materials of construction, service environment, or previous 

failure history. The samples should be biased toward locations most susceptible to the 

specific aging effect of concern in the period of extended operation. Provisions on 

expanding the sample size when degradation is detected in the initial sample should 

also be 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 operating experience may be considered in 

evaluating the appropriateness of the technique and frequency.

2. This program element describes “how” the data collected are evaluated and may also 

include trending for a forward look. This includes an evaluation of the results against the 

acceptance criteria and a prediction regarding the rate of degradation in order to confirm 

that timing of the next scheduled inspection will occur before a loss of SC-intended

function. 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 
NUREG-1800, Rev. 2 A.1-6 December 2010

the current monitoring results with previous monitoring results in order to make 

predictions for the future.

A.1.2.3.6 Acceptance Criteria

1. The quantitative or qualitative acceptance criteria of the program and its basis should be 

described. The acceptance criteria, against which the need for corrective actions are 

evaluated, should ensure that the structure- and component-intended function(s) are 

maintained consistent with all CLB design conditions during the period of extended 

operation. The program should include a methodology for analyzing the results against 

applicable acceptance criteria.

For example, carbon steel pipe wall thinning may occur under certain conditions due to 

FAC. An AMP for FAC may consist of periodically measuring the pipe wall thickness and 

comparing that to a specific minimum wall acceptance criterion. Corrective action is 

taken, such as piping replacement, before deadweight, seismic, and other loads, and 

this acceptance criterion must be appropriate to ensure that the thinned piping would be 

able to carry these CLB design loads. This acceptance criterion should provide for timely 

corrective action before loss of intended function under these CLB design loads.

2. Acceptance criteria could be specific numerical values, or could consist of a discussion 

of the process for calculating specific numerical values of conditional acceptance criteria 

to ensure that the structure- and component-intended function(s) will be maintained 

under all CLB design conditions. Information from available references may be cited.

3. It is not necessary to justify any acceptance criteria taken directly from the design basis 

information that is included in either the final safety analysis report (FSAR), 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 NRCendorsed evaluation methodology. Also, it is not necessary to discuss CLB design loads 

if the acceptance criteria do not permit degradation because a structure and component 

without degradation should continue to function as originally designed. Acceptance 

criteria, which do permit degradation, are based on maintaining the intended function 

under all CLB design loads.

A.1.2.3.7 Corrective Actions

1. 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 root 

cause determination and prevention of recurrence, should be timely. 

2. If corrective actions permit analysis without repair or replacement, the analysis should 

ensure that the structure- and component-intended function(s) are maintained consistent 

with the CLB.
December 2010 A.1-7 NUREG-1800, Rev. 2

3. For safety-related components, an applicant’s 10 CFR Part 50, Appendix B, Quality 

Assurance Program, is an acceptable means to confirm that the corrective actions are 

done in a manner consistent with the condition monitoring program, preventive program, 

mitigative program, or performance monitoring program that is credited for aging 

management. For example, for a plant-specific condition monitoring program that is 

based on ASME Section XI requirements, the implementation of the Appendix B 

program should ensure that any corrective actions are performed in accordance with 

applicable Code requirements or NRC-approved Code cases. 

A.1.2.3.8 Confirmation Process

1. The confirmation process should be described. The process ensures that preventive 

actions are adequate and that appropriate corrective actions have been completed and 

are effective.

2. The effectiveness of prevention and mitigation programs should be verified periodically. 

For example, in managing internal corrosion of piping, a mitigation program (water 

chemistry) may be used to minimize susceptibility to corrosion. However, it also may be 

necessary to have a condition monitoring program (ultrasonic inspection) to verify that 

corrosion is indeed insignificant.

3. When corrective actions are necessary, 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.

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. Any AMPs to be relied on for license renewal should have regulatory and administrative 

controls. That is the basis for 10 CFR 54.21(d) to require that the FSAR supplement 

include a summary description of the programs and activities for managing the effects of 

aging for license renewal. Thus, any informal programs relied on to manage aging for 

license renewal must be administratively controlled and included in the FSAR 

supplement.

A.1.2.3.10 Operating Experience

1. Consideration of future plant-specific and industry operating experience relating to aging 

management programs should be discussed. Reviews of operating experience by the 

applicant in the future may identify areas where aging management programs should be 

enhanced or new programs developed. An applicant should commit to a future review of 

plant-specific and industry operating experience to confirm the effectiveness of its aging 

management programs or indicate a need to develop new aging management programs. 

This information should provide objective evidence to support the conclusion that the 

effects of aging will be managed adequately so that the structure and component 

intended function(s) will be maintained during the period of extended operation.

2. Operating experience with existing programs should be discussed. The operating 

experience of AMPs that are existing programs, including past corrective actions 
NUREG-1800, Rev. 2 A.1-8 December 2010

resulting in program enhancements or additional programs, should be considered. A

past failure would not necessarily invalidate an AMP because the feedback from 

operating experience should have resulted in appropriate program enhancements or 

new programs. This information can show where an existing program has succeeded 

and where it has failed (if at all) in intercepting aging degradation in a timely manner. 

This information should provide objective evidence to support the conclusion that the 

effects of aging will be managed adequately so that the structure- and componentintended function(s) will be maintained during the period of extended operation.

3. For new AMPs that have yet to be implemented at an applicant’s facility, the programs 

have not yet generated any operating experience (OE). However, there may be other 

relevant plant-specific OE at the plant or generic OE in the industry that is relevant to the 

AMP’s program elements even though the OE was not identified as a result of the 

implementation of the new program. Thus, for new programs, an applicant may need to 

consider the impact of relevant OE that results from the past implementation of its 

existing AMPs that are existing programs and the impact of relevant generic OE on 

developing the program elements. Therefore, operating experience applicable to new 

programs should be discussed. Additionally, an applicant should commit to a review of 

future plant-specific and industry operating experience for new programs to confirm their 

effectiveness.

A.1.3 References

1. NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The 

License Renewal Rule,” Nuclear Energy Institute, Revision 6.
December 2010 A.1-9 NUREG-1800, Rev. 2 

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

Element Description 

1. Scope of Program Scope of program includes the specific structures and 

components subject to an AMR for license renewal. 

2. Preventive Actions Preventive actions should prevent or mitigate aging 

degradation. 

3. Parameters Monitored 

or Inspected 

Parameters monitored or inspected should be linked to the 

degradation of the particular structure or componentintended function(s). 

4. Detection of Aging 

Effects 

Detection of aging effects should occur before there is a 

loss of structure or component-intended function(s). This 

includes aspects such as method or technique (i.e., visual, 

volumetric, surface inspection), frequency, sample size, 

data collection, and timing of new/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 structure or 

component-intended function(s) are maintained under all 

CLB design conditions during the period of extended 

operation. 

7. Corrective Actions Corrective actions, including root cause determination and 

prevention of recurrence, should be timely. 

8. Confirmation Process Confirmation process should ensure that preventive actions 

are adequate and that appropriate corrective actions have 

been completed and are effective. 

9. Administrative Controls Administrative controls should provide a formal review and 

approval process. 

10. Operating Experience If the AMP is an existing program, operating experience of 

the AMP, including past corrective actions resulting in 

program enhancements or additional programs, should 

provide objective evidence to support the conclusion that 

the effects of aging will be managed adequately so that the 

structure- and component-intended function(s) will be 

maintained during the period of extended operation. 

December 2010 A.2-1 NUREG-1800, Rev. 2

A.2 QUALITY ASSURANCE FOR AGING MANAGEMENT PROGRAMS (BRANCH 

TECHNICAL POSITION IQMB-1)

A.2.1 Background

The license renewal applicant is required to demonstrate that the effects of aging on structures 

and components 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 

(CLB) of the facility for the period of extended operation. Therefore, those aspects of the AMR 

process that affect quality of safety-related structures, systems, and components are subject to 

the quality assurance (QA) requirements of 10 CFR Part 50 Appendix B. For nonsafety-related 

structures and components (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 

RLSB-1 (Appendix A.1 of this standard review plan for license renewal [SRP-LR]). The 

confirmation process ensures that preventive actions are adequate and that appropriate 

corrective actions have been completed and are effective. Administrative controls should 

provide for a formal review and approval process. Reference 1 describes how a license renewal 

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 branch technical position (IQMB-1) is to 

describe an acceptable process for implementing the corrective actions, the confirmation 

process, and administrative controls of aging management programs for license renewal.

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 aging management program 

consistent with the CLB of the facility for the period of extended operation. 

2. For nonsafety-related SCs that are subject to an AMR for license renewal, 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 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 nonsafetyrelated SCs that are subject to an AMR for license renewal, the applicant’s proposal is 

reviewed on a case-by-case basis following the guidance in Branch Technical Position 

RLSB-1 (Appendix A.1 of this SRP-LR).

A.2.3 References

1. NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear Regulatory 

Commission, Revision 2, 2010.

December 2010 A.3-1 NUREG-1800, Rev. 2

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 NRC’s formal resolution process set forth in NUREG-0933, “Resolution of Generic Safety 

Issues,” which is updated periodically (Ref. 1). 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 license renewal review. The purpose of this branch technical 

position (RLSB-2) is to address the license renewal treatment of an aging effect or a TLAA 

which is a subject of an USI or a GSI (60 FR 22484).

Table A.3-1 provides examples to help determine whether a USI or GSI should or should not be 

specifically addressed for license renewal, based on lessons learned from the staff review of the 

initial license renewal applications. However, two of these examples (GSI-23 and -190) have 

been resolved by the staff. They are included in the examples for illustrative purposes.

A.3.2 Branch Technical Position

A.3.2.1 Treatment of GSIs

1. The license renewal rule requires that aging effects be managed to ensure that the 

structure- and component-intended function(s) are maintained and that TLAAs are 

evaluated for license renewal. Thus, all applicable aging effects of structures and 

components subject to an AMR and all TLAAs must be evaluated, regardless of whether 

they are associated with GSIs or USIs.

2. USIs and HIGH- and MEDIUM-priority issues described in NUREG-0933 Appendix B 

(Ref. 1) that involve aging effects for structures and components subject to an AMR or 

TLAAs are specifically addressed. The version of NUREG-0933 that is current on the 

date 6 months before the date of the license renewal application is used to identify such 

issues. Prior to Safety Evaluation Report (SER) completion, any new issues contained in 

later versions of NUREG-0933 should be reviewed and resolved if applicable to the 

applicant’s plant. New issues are addressed by using one of the approaches described 

in Position A.3.2.2 below.

3. New generic safety issues, designated as USI, HIGH-, or MEDIUM- priority after the 

application has been submitted, that involve aging effects for structures and components 

subject to an aging management review or TLAA should be submitted in the annual 

update of the application.

4. During the preparation and review of a license renewal application, an applicant or the 

NRC may become aware of an aging management or TLAA issue that is generically 

applicable to other nuclear plants. If issues have generic applicability (but are not yet 

part of the formal GSIs resolution process as identified in NUREG-0933), an applicant 

should still address the issue to demonstrate that the effects of aging are or will be 

managed adequately or that TLAAs are evaluated for the period of extended operation.
NUREG-1800, Rev. 2 A.3-2 December 2010

A.3.2.2 Approaches for Addressing GSIs (60 FR 22484)

One of the following approaches may be used:

1. If resolution has been achieved before issuance of a renewed license, implementation of 

that resolution is incorporated within the license renewal application. The plant-specific 

implementation information is provided.

2. A technical rationale is provided that demonstrates that the CLB will be maintained until 

some later time in the period of extended operation, at which point one or more 

reasonable options (for example, replacement, analytical evaluation, or a 

surveillance/maintenance program) become available to adequately manage the effects 

of aging. An applicant describes the basis for concluding that the CLB is maintained 

during the period of extended operation and briefly describes options that are technically 

feasible during the period of extended operation to manage the effects of aging, but 

does not have to preselect which option to use.

3. An aging management program is developed that, for that plant, incorporates a 

resolution to the aging effects issue.

4. An amendment of the CLB (as a separate action outside the license renewal application) 

is proposed that, if approved, removes the intended function(s) from the CLB. The 

proposed CLB amendment is reviewed under 10 CFR Part 50 and is not a review area 

for license renewal.

A.3.3 References

1. NUREG-0933, “Resolution of Generic Safety Issues,” Supplement 32, U.S. Nuclear 

Regulatory Commission, August 2008. 

2. NRC Regulatory Issue Summary 2000-02, “Closure of Generic Safety Issue 23, Reactor 

Coolant Pump Seal Failure,” February 15, 2000.

3. Letter from Ashok C. Thadani of the Office of Nuclear Regulatory Research, NRC, to William 

D. Travers, Executive Director of Operations, NRC, dated December 26, 1999.

4. SECY 94-225, “Issuance of Proposed Rulemaking Package on GSI-23, Reactor Coolant 

Pump Seal Failure,” August 26, 1994.

5. Information Notice 93-61, “Excessive Reactor Coolant Leakage Following a Seal Failure in a 

Reactor Coolant Pump or Reactor Recirculation Pump,” August 9, 1993.

6. Deleted.

7. NRC Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

Instrumentation and Control Cables” dated May 2, 2003.
December 2010 A.3-3 NUREG-1800, Rev. 2

Table A.3-1 Examples of Generic Safety Issues that Should/Should Not Be 

Specifically Addressed for License Renewal and Basis for Disposition

Example Disposition

GSI-23, “Reactor Coolant 

Pump Seal Failures”

This issue relates to reactor coolant pump seal failures, which 

challenge the makeup capacity of the emergency core cooling 

system in PWRs. Although GSI-23 originally addressed seal 

performance both during normal operation and during loss of 

seal cooling conditions, it has been modified to address only seal 

performance during loss of seal cooling conditions (Refs. 4 

and 5). Loss of all seal cooling may cause the reactor coolant 

pump seals to fail or leak excessively. Because the reactor 

coolant pump seal performance during loss of seal cooling 

conditions is not an issue that involves AMR or TLAA, GSI-23 

need not be specifically addressed for license renewal (Ref. 2).

GSI-168, “Environmental 

Qualification of Electrical 

Equipment”

This issue relates to aging of electrical equipment that is subject 

to environmental qualification requirements. Environmental 

qualification is a TLAA for license renewal. 

Regulatory Issue Summary (RIS) 2003-09 was issued on May 2, 

2003, to inform addressees of the results of the technical 

assessment of GSI-168, "Environmental Qualification of 

Electrical Equipment.” This RIS requires no action on the part of 

the addressees (Ref. 7).

GSI-173.A, “Spent Fuel 

Storage Pool: Operating 

Experience”

This issue relates to the potential for a sustained loss of spent 

fuel pool cooling capacity and the potential for a substantial loss 

of spent fuel pool coolant inventory. The staff evaluated the issue 

and concluded that no actions will be taken for operating plants. 

As indicated in NUREG-0933, the staff is pursuing regulatory 

improvement changes to RG 1.13, “Spent Fuel Storage Facility 

Design Basis,” and NUREG-0800, “Standard Review Plan for the 

Review of Safety Analysis Reports for Nuclear Power Plants.” 

Thus, GSI-173.A need not be specifically addressed for license 

renewal.

GSI-190, “Fatigue Evaluation of 

Metal Components for 60-Year 

Plant Life”

This issue relates to environmental effects on fatigue of reactor 

coolant system components for 60 years. Fatigue is also a TLAA 

for license renewal. Thus, GSI-190 was specifically addressed 

for license renewal by the initial license renewal applicants. This 

GSI has now been resolved (Ref. 3).