NUREG-1800, Rev. 1

Standard Review Plan for

Review of License Renewal

Applications for Nuclear

Power Plants

Manuscript Completed: September 2005

Date Published: September 2005

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
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September 2005 iii NUREG-1800, Rev. 1

ABSTRACT

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

Plants (SRP-LR) provides guidance to Nuclear Regulatory Commission 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 is also intended to 

make information about regulatory matters 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 (1) who performs the review, (2) the matters that are reviewed, 

(3) the basis for review, (4) the way the review is accomplished, and (5) the conclusions that are 

sought. 

Paperwork Reduction Act

The information collections contained in this NUREG are covered by the requirements of 10 

CFR Parts 50 and 54, which were approved by the Office of Management and Budget, approval 

numbers 3150-0011 and 3150-0155.

Public Protection Notification

If a means used to impose an information collection does not display a currently valid OMB 

control number, the NRC may not conduct or sponsor, and a person is not required to respond 

to, the information collection.
NUREG-1800, Rev. 1 iv September 2005

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September 2005 v NUREG-1800, Rev. 1

TABLE OF CONTENTS

Page

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

ABBREVIATIONS .................................................................................................................. xi

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 RESULTS.............................................. 3-i

3.0 AGING MANAGEMENT REVIEW RESULTS.............................................................. 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

3.6 AGING MANAGEMENT OF ELECTRICAL AND

INSTRUMENTATION AND CONTROLS .................................................................... 3.6-1
NUREG-1800, Rev. 1 vi September 2005

TABLE OF CONTENTS (continued)

Page

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 ANALYSIS....................................................................................... 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
September 2005 vii NUREG-1800, Rev. 1

LIST OF TABLES

Page

Table 1.1-1. Acceptance Review Checklist for Docketing of Timely and Sufficient 

Renewal Application ......................................................................................... 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 ......................................................................................... 2.2-6

Table 2.3-1. Examples of Mechanical Components Scoping and 

Basis for Disposition ......................................................................................... 2.3-6

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

Disposition......................................................................................................... 2.3-7

Table 2.3-3. Examples of Mechanical Component Intended Functions............................... 2.3-7

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

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

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

Scoping and Corresponding Review Procedures ............................................ 2.5-7

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

Internals, and Reactor Coolant System Evaluated in Chapter IV 

of the GALL Report ........................................................................................... 3.1-21

Table 3.1-2. FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System............................................................ 3.1-39

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

Features Evaluated in Chapter V of the GALL Report..................................... 3.2-14

Table 3.2-2. FSAR Supplement for Aging Management of Engineered Safety 

Features ............................................................................................................ 3.2-25
NUREG-1800, Rev. 1 viii September 2005

LIST OF TABLES (continued)

Page

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

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

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems.................... 3.3-35

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

Conversion System Evaluated in Chapter VIII of the GALL Report ................ 3.4-16

Table 3.4-2. FSAR Supplement for Aging Management of Steam and Power 

Conversion System........................................................................................... 3.4-22

Table 3.5-1. Summary of Aging Management Programs for Structures and 

Component Supports Evaluated in Chapters II and III of the 

GALL Report ..................................................................................................... 3.5-19

Table 3.5-2. FSAR Supplement for Aging Management of Structures and 

Component Supports........................................................................................ 3.5-35

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

Components Evaluated in Chapter VI of the GALL Report ............................. 3.6-7

Table 3.6-2. FSAR Supplement for Aging Management of Electrical and 

Instrumentation and Control System ................................................................ 3.6-11

Table 4.1-1. Identification of Potential Time-Limited Aging Analyses and 

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

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

Table 4.1-3. Additional Examples of Plant-Specific TLAAs as Identified by the 

Initial License Renewal Applicants ................................................................... 4.1-6

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

Embrittlement TLAA Evaluation........................................................................ 4.2-12

Table 4.3-1. Stress Range Reduction Factors...................................................................... 4.3-10

Table 4.3-2. Example of FSAR Supplement for Metal Fatigue TLAA Evaluation................ 4.3-10

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
September 2005 ix NUREG-1800, Rev. 1

LIST OF TABLES (continued)

Page

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

Metal Containments, and Penetrations Fatigue TLAA Evaluation................... 4.6-6

Table A.1-1. Elements of an Aging Management Program for License Renewal................ A.1-8

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
NUREG-1800, Rev. 1 x September 2005

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September 2005 xi NUREG-1800, Rev. 1

ABBREVIATIONS

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

BTP branch technical position

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

DOR Division of Operating Reactors

DRIP Division of Regulatory Improvement Programs

ECCS emergency core cooling system

ECT eddy current testing

EDG emergency diesel generator

EFPY effective full power year

EPRI Electric Power Research Institute

EPU extended power uprate

FAC flow-accelerated corrosion

FR Federal Register

FSAR Final Safety Analysis Report

GALL Generic Aging Lessons Learned

GE General Electric

GL generic letter

GSI generic safety issue

HAZ heat-affected zone

HELB high-energy line break

HPCI high-pressure coolant injection

HVAC heating, ventilation, and air conditioning
NUREG-1800, Rev. 1 xii September 2005

ABBREVIATIONS (continued)

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

ITG Issues Task Group

LCD liquid crystal display

LED light-emitting diode

LER licensee event report

LOCA loss of coolant accident

LRA license renewal application

LTOP low-temperature overpressure protection

MIC microbiologically-influenced corrosion

MEAP material/environment/aging effect/program as summarized on AMR line-items

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 non-safety related

NSSS nuclear steam supply system

ODSCC outside diameter stress corrosion cracking

OM operation and maintenance

P&ID piping and instrument diagrams

PLL predicted lower limit

PRA probabilistic risk analysis

PT penetrant testing

P-T pressure-temperature

PTS pressurized thermal shock

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance
September 2005 xiii NUREG-1800, Rev. 1

ABBREVIATIONS (continued)

RCIC reactor core isolation cooling

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG Regulatory Guide

RLEP License Renewal & Environmental Impacts Program

RPV reactor pressure vessel

RT reference temperature

SBO station blackout

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

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

TLAA time-limited aging analysis

UFSAR updated final safety analysis report

USI unresolved safety issue

UT ultrasonic testing

UV ultraviolet

WSLR within scope of license renewal
NUREG-1800, Rev. 1 xiv September 2005

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September 2005 1 NUREG-1800, Rev. 1

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 is also 

intended to make information about regulatory matters 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. 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 shall include an integrated plant assessment (IPA), current licensing basis (CLB) 

changes during review of the application by 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, a license renewal application 

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 (1) whether there is reasonable 

assurance that the activities authorized by the renewed license will continue to be conducted in 

accordance with the CLB and (2) whether any changes made to the plant’s CLB to comply with 

10 CFR Part 54 are in accord with the Atomic Energy Act of 1954 and NRC regulations.

Before submitting a license renewal application, an applicant should have analyzed the plant to 

ensure that actions have been or will be taken to (1) 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 (2) evaluate TLAAs. The license renewal application 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. Regulatory Guide 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 a 

license renewal application. The SRP-LR sections are keyed to and are numbered according to 

the section numbers RG 1.188.

During the review of the initial license renewal applications, NRC staff and the applicants have 

found that most of the programs to manage aging that are credited for license renewal are 

existing programs. 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 
Draft NUREG-1800, Rev. 1 2 September 2005

where existing programs should be augmented for license renewal. Under the terms of the 

SRM, the SRP-LR would reference a “Generic Aging Lessons Learned” (GALL) report, which 

evaluates existing programs generically, to document (1) the conditions under which existing 

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

(2) 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 repeat their review of 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 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 applicants have 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: (1) Administrative Information; (2) Scoping and 

Screening Methodology for Identifying Structures and Components Subject to Aging 

Management Review, and Implementation Results; (3) Aging Management Review Results; and 

(4) Time-Limited Aging Analyses. The appendixes 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 (1) who performs the review, (2) the matters that are 

reviewed, (3) the basis for review, (4) the way the review is accomplished, and (5) 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 are also 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,” (3

rd Edition, July 1981 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 are 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.
September 2005 3 NUREG-1800, Rev. 1

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 appendixes 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 the initial 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 will be revised and updated periodically, as 

needed, to incorporate experience gained during future 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. The table of contents 

indicates the revision numbers of the most current sections. 
NUREG-1800, Rev. 1 4 September 2005

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September 2005 1-i NUREG-1800, Rev. 1

CHAPTER 1

ADMINISTRATIVE INFORMATION
NUREG-1800, Rev. 1 1-ii September 2005

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September 2005 1.1-1 NUREG-1800, Rev. 1

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 (1) 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 

(2) 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, which was written to comply with the 

Administrative Procedures Act, means that the current license will not expire until the 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.

In determining 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. 1 1.1-2 September 2005

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 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, 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.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 should check 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 FSAR 

supplement, and technical specification changes, respectively. Chapters 2, 3, and 4 of the 

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 

 

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

Plant Operating Licenses” (Ref. 1), provides guidance on the format and content of a renewal 

application.
September 2005 1.1-3 NUREG-1800, Rev. 1

reviewer should check the “Yes” column if it is determined that the renewal application contains 

environmental information consistent with the requirements of 10 CFR Part 51. 

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. By checking the “No” column for any checklist item, except Item VI as discussed 

in Subsection 1.1.3.2, the reviewer 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 determines that the application is not acceptable for docketing as a sufficient

application, the letter to the applicant should clearly state that (1) the application is not sufficient 

and is not acceptable for docketing, and (2) the current license will expire at its expiration date. 

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

an opportunity for the applicant to modify its application to provide the missing or incomplete 

information. The reviewer should review the modified 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 will be 

published in the Federal Register.

If the application is acceptable for docketing as a sufficient application, the staff should begin its 

technical review. For license renewal applications, the NRC intends to maintain the docket 

number of the current operating license for administrative convenience.

1.1.3.2 Timeliness of Application

Upon receipt of a tendered application for license renewal, the reviewer performs a docketing 

and sufficiency review, as discussed in Subsection 1.1.3.1.

If the 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 an 

applicant has to modify its application, as discussed in Subsection 1.1.3.1, before the staff can 

find the application acceptable for docketing as a sufficient application, the modified application 

should be submitted at least 5 years before the expiration of the current operating license

unless an exemption is granted.

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 to the applicant should clearly state that (1) the application is not 

timely, (2) the provisions in 10 CFR 2.109(b) have not been satisfied, and (3) the current license 
NUREG-1800, Rev. 1 1.1-4 September 2005

will expire on the expiration date. However, if the application is otherwise determined to be 

acceptable for docketing, the technical review can begin.

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 in 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 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.
September 2005 1.1-5 NUREG-1800, Rev. 1

Table 1.1-1. Acceptance Review Checklist for Docketing of

Timely and Sufficient Renewal Application

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 foreign-owned 

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

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

of current license [10 CFR 54.17(c)]

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

licenses [10 CFR 54.17(d)]

6. Information incorporated by reference in the application is contained 

in other documents previously filed with the Commission, and the 

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

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

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

[10 CFR 54.17(f)]

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

control of accessibility to such information is provided [10 CFR 

54.17(g)]
NUREG-1800, Rev. 1 1.1-6 September 2005

Table 1.1-1. Acceptance Review Checklist for Docketing of

Timely and Sufficient Renewal Application (continued) 

Yes No

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

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

A. Name of applicant

B. Address of applicant

C. Business description

D. Citizenship and ownership details

E. License information

F. Construction or alteration dates

G. Regulatory agencies and local publications

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

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

to account for the proposed change in the expiration date

[10 CFR 54.19(b)]

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)]
September 2005 1.1-7 NUREG-1800, Rev. 1

Table 1.1-1. Acceptance Review Checklist for Docketing of

Timely and Sufficient Renewal Application (continued) 

Yes No

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)]

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
NUREG-1800, Rev. 1 1.1-8 September 2005

Table 1.1-1. Acceptance Review Checklist for Docketing of

Timely and Sufficient Renewal Application (continued) 

Yes No

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
September 2005 2-i NUREG-1800, Rev. 1

CHAPTER 2 

SCOPING AND SCREENING METHODOLOGY FOR 

IDENTIFYING STRUCTURES AND COMPONENTS 

SUBJECT TO AGING MANAGEMENT 

REVIEW AND IMPLEMENTATION RESULTS
NUREG-1800, Rev. 1 2-ii September 2005

This Page Intentionally Left Blank
September 2005 2.1-1 NUREG-1800, Rev. 1

2.1 SCOPING AND SCREENING METHODOLOGY

Review Responsibilities

Primary - Branch responsible for quality assurance

Secondary - Branches responsible for systems, as appropriate

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

• 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.
NUREG-1800, Rev. 1 2.1-2 September 2005

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, or hurricanes, and internal events, such as a high-energyline break. Information regarding design basis events as defined in 10 CFR 
September 2005 2.1-3 NUREG-1800, Rev. 1

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: “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
NUREG-1800, Rev. 1 2.1-4 September 2005

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 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 

database 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 renewal. For example, NRC 

Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification,” states:
September 2005 2.1-5 NUREG-1800, Rev. 1

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.

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. 
NUREG-1800, Rev. 1 2.1-6 September 2005

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 the applicable functions 

of the SSCs 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) industry-wide 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. 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 nonpiping 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 industry-wide 

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

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

such as significant operating experience reports (SOERs), and engineering evaluations.
September 2005 2.1-7 NUREG-1800, Rev. 1

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 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 
NUREG-1800, Rev. 1 2.1-8 September 2005

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, industry-wide 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 non-seismically-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, 

industry wide experience [as applicable], safety analyses, or plant evaluations) that is specifically 

relied upon for compliance with, the applicable NRC regulation. For example, if analysis of 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 that 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
September 2005 2.1-9 NUREG-1800, Rev. 1

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 plant system portion of 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.

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).

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 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.
NUREG-1800, Rev. 1 2.1-10 September 2005

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 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.

2.1.6 References
September 2005 2.1-11 NUREG-1800, Rev. 1

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

Part 54 - The License Renewal Rule,” Nuclear Energy Institute.

2. Regulatory Guide 1.29, Rev. 2, “Seismic Design Classification,” September 1978.

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

Power Plants,” July 1981.

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. Deleted.

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

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

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

August 5, 1999.

9. 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.

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

dated October 8,1999.

11. NEI 95-10, Rev. 0, “Industry Guideline for Implementing the Requirements of 10 CFR 

Part 54 - The License Renewal Rule,” Nuclear Energy Institute, March 1, 1996.

12. 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.

13. 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.

14. 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.
NUREG-1800, Rev. 1 2.1-12 September 2005

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
September 2005 2.1-13 NUREG-1800, Rev. 1

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 

makes 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. 11), 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 44oF, 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 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
NUREG-1800, Rev. 1 2.1-14 September 2005

Table 2.1-2 Specific Staff Guidance on Scoping (continued)

Issue Guidance

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) 

industry-wide 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 nonsafetyrelated, 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 nonsafetyrelated piping identified as a Seismic II/I component in the applicant’s CLB (Ref. 8).

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-seismicallyqualified 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, industry-wide 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. 8).
September 2005 2.1-15 NUREG-1800, Rev. 1

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 O-rings; (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. 9).

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. 10).

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.
NUREG-1800, Rev. 1 2.1-16 September 2005

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 leaktight barrier to protect public 

health and safety in the event of any postulated design-basis events.
September 2005 2.1-17 NUREG-1800, Rev. 1

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 safetyrelated SSCs

Pressure Boundary

Provide pressure-retaining boundary so that sufficient flow at adequate 

pressure is delivered, or provide fission product barrier for containment 

pressure boundary, or provide containment isolation for fission product 

retention

Spray Convert fluid into spray

Structural Integrity 

(Attached)

Nonsafety-related component that maintains mechanical and structural 

integrity to provide structural support to attached safety-related piping and 

components

Structural Support Provide structural and/or functional support to safety-related and/or 

nonsafety-related components

Throttle Provide flow restriction
NUREG-1800, Rev. 1 2.1-18 September 2005

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

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
September 2005 2.1-19 NUREG-1800, Rev. 1

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)

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

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

Sprinklers 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)
NUREG-1800, Rev. 1 2.1-20 September 2005

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)

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

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
September 2005 2.1-21 NUREG-1800, Rev. 1

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)

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

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, isolatedphase bus, nonsegregated-phase bus, 

segregated-phase bus, switchyard bus)

Yes

78 Electrical and I&C Chargers, Converters, Inverters

(e.g., converters-voltage/current, convertersvoltage/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

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
NUREG-1800, Rev. 1 2.1-22 September 2005

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)

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, motor-generator 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

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
September 2005 2.1-23 NUREG-1800, Rev. 1

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)

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

102 Electrical and I&C Switches

(e.g., differential pressure indicating switches, 

differential pressure switches, pressure indicator 

switches, pressure switches, flow switches, 

conductivity switches, level indicating switches, 

temperature indicating switches, temperature 

switches, moisture switches, position switches, 

vibration switches, level switches, control 

switches, automatic transfer switches, manual 

transfer switches, manual disconnect switches, 

current switches, limit switches, knife switches)

No

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
NUREG-1800, Rev. 1 2.1-24 September 2005

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)

105 Electrical and I&C Transmitters

(e.g., differential pressure transmitters, pressure 

transmitters, flow transmitters, level 

transmitters, radiation transmitters, static 

pressure transmitters)

No

106 Valves Hydraulic Operated Valves Yes (Bodies)

107 Valves Explosive Valves Yes (Bodies)

108 Valves Manual Valves Yes (Bodies)

109 Valves Small Valves Yes (Bodies)

110 Valves Motor-Operated Valves Yes (Bodies)

111 Valves Air-Operated Valves Yes (Bodies)

112 Valves Main Steam Isolation Valves Yes (Bodies)

113 Valves Small Relief Valves Yes (Bodies)

114 Valves Check Valves Yes (Bodies)

115 Valves Safety Relief Valves Yes (Bodies)

116 Valves Dampers, louvers, and gravity dampers Yes (Housings)

117 Tanks Air Accumulators Yes

118 Tanks Discharge Accumulators (Dampers) Yes

119 Tanks Boron Acid Storage Tanks Yes

120 Tanks Above Ground Oil Tanks Yes

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
September 2005 2.2-1 NUREG-1800, Rev. 1

2.2 PLANT-LEVEL SCOPING RESULTS 

Review Responsibilities

Primary - Plant Systems Branch

Secondary - Branches responsible for systems and structures

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 plant-level 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.

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 
NUREG-1800, Rev. 1 2.2-2 September 2005

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.

• 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.

• 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, 

other staff members review the applicant’s scoping and screening methodology separately 
September 2005 2.2-3 NUREG-1800, Rev. 1

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 the 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. 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 on site 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. 1 2.2-4 September 2005

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. 2, “Seismic Design Classifications,” September 1978.
September 2005 2.2-5 NUREG-1800, Rev. 1

Table 2.2-1. Examples of System and Structure Scoping and

Basis for Disposition

Example Disposition

Recirculation cooling water system One function of the recirculation cooling water system is to remove 

decay heat from the stored fuel in the spent fuel pool via the spent 

fuel pool cooling system. However, the spent fuel pool cooling 

system at the subject facility is not safety-related, and, following a 

seismic event, the safety-related spent fuel pool structure and 

spent fuel pool makeup water supplies ensure the adequate 

removal of decay heat to prevent potential offsite exposures 

comparable to those described in 10 CFR Part 100. Therefore, 

the recirculation cooling water system is not within the scope of 

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 safety-related emergency diesel generator building. In 

addition, the UFSAR indicates that certain equipment attached to 

the roof of the building has been anchored to resist tornado wind 

loads. Thus, the SBO diesel generator building is within the scope 

of license renewal.
NUREG-1800, Rev. 1 2.2-6 September 2005

This Page Intentionally Left Blank
September 2005 2.3-1 NUREG-1800, Rev. 1

2.3 SCOPING AND SCREENING RESULTS: MECHANICAL SYSTEMS 

Review Responsibilities 

Primary - Branches responsible for systems

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 piping and instrument 

diagrams (P&IDs) or other media. This is “scoping” of mechanical components in a system to 

identify those that are WSLR for a system.
NUREG-1800, Rev. 1 2.3-2 September 2005

For these 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 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)].
September 2005 2.3-3 NUREG-1800, Rev. 1

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 subject to an AMR, but 

not components that are WSLR. Whereas in the past LRAs have included a table of components 

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 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, 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
NUREG-1800, Rev. 1 2.3-4 September 2005

• 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 markedup 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

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 component 

intended functions.
September 2005 2.3-5 NUREG-1800, Rev. 1

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. 1 2.3-6 September 2005

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 plant-specific basis.
September 2005 2.3-7 NUREG-1800, Rev. 1

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.

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 boundary intended function, but may 

not have a heat transfer function. Similarly, not all orifices have flow restriction as an intended function.
NUREG-1800, Rev. 1 2.3-8 September 2005

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September 2005 2.4-1 NUREG-1800, Rev. 1

2.4 SCOPING AND SCREENING RESULTS: STRUCTURES 

Review Responsibilities

Primary - Mechanical and Civil Engineering Branch

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.

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 
NUREG-1800, Rev. 1 2.4-2 September 2005

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, 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 
September 2005 2.4-3 NUREG-1800, Rev. 1

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 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 “long lived”).

2.4.3.2 Structural Components Subject to an Aging Management Review

In general, structural components are “passive” and “long lived.” Thus, they are subject to an AMR 

if they are 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 AMR by the applicant because the 

applicant has the option to include more structural components than the rule requires to be subject 

to an AMR.

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 
NUREG-1800, Rev. 1 2.4-4 September 2005

being WSLR. Similarly, if a non-safety-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, 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. 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 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
September 2005 2.4-5 NUREG-1800, Rev. 1

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, "A Prioritization of Generic Safety Issues,” U.S. Nuclear Regulatory Commission, 

June 2004.
NUREG-1800, Rev. 1 2.4-6 September 2005

Table 2.4-1. Examples of Structural Components Scoping/Screening

and Basis for Disposition

Example Disposition

Roof of turbine building An applicant indicates that degradation or loss of its turbine 

building roof will not result in the loss of any intended functions. 

The turbine building contains safety-related SSCs in the 

basement, which would remain sheltered and protected by 

several reinforced concrete floors if the turbine building roof 

were to degrade. Because this roof does not perform an 

intended function, it is not 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.
September 2005 2.5-1 NUREG-1800, Rev. 1

2.5 SCOPING AND SCREENING RESULTS: ELECTRICAL AND INSTRUMENTATION 

AND CONTROLS SYSTEMS

Review Responsibilities

Primary - Branch responsible for electrical and instrumentation and controls engineering

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 plant-level “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”) to be 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 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 
NUREG-1800, Rev. 1 2.5-2 September 2005

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:

• The onsite power system meeting the requirements under 10 CFR 54.4(a)(1) (safetyrelated systems)
September 2005 2.5-3 NUREG-1800, Rev. 1

• 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). This path typically includes the switchyard circuit breakers that connect 

to the offsite system power transformers (startup transformers), the transformers 

themselves, the intervening overhead or underground circuits between circuit 

breaker and transformer and transformer and onsite electrical distribution system, 

and the associated control circuits and structures.

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 

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). 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.
NUREG-1800, Rev. 1 2.5-4 September 2005

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 applicants to identify components that are subject to an AMR, but

not components that are WSLR. 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 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:

• 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.
September 2005 2.5-5 NUREG-1800, Rev. 1

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).

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 Plants-Electrical 

Cable and Terminations,” Sandia National Laboratories, September 1996,

page 6-11.
NUREG-1800, Rev. 1 2.5-6 September 2005

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 directburied cables in trenches between these building 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 on site, 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.
September 2005 3-i NUREG-1800, Rev. 1

CHAPTER 3

AGING MANAGEMENT REVIEW 
NUREG-1800, Rev. 1 3-ii September 2005

This Page Intentionally Left Blank
September 2005 3.0-1 NUREG-1800, Rev. 1

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) or aging 

management programs (AMPs) identified in the applicant’s LRA. The PM should document to 

which organization each AMR or AMP is assigned. The assigned AMRs and AMPs should be 

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. 

The NRC divisions that are usually assigned responsibility for the review of AMRs and AMPs 

are the Division of Engineering (DE), Division of System Safety Analysis (DSSA), and the 

Division of Regulatory Improvement Program (DRIP) License Renewal and Environmental 

Impacts Program (RLEP). Typically, the PM will assign DRIP/RLEP to review the AMRs and 

AMPs that the LRA identifies as being consistent with the GALL Report or NRC-approved 

precedents. As common exceptions to this assignment, the PM will assign to DE those AMRs 

and AMPs that address issues identified as emerging technical issues. Usually, AMRs and 

AMPs that are not in one of the aforementioned categories are assigned to DE. 

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

The NRC divisions assigned the AMP should review 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 quality assurance should 

verify 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 (e.g., use of a process other than the applicant’s 10 CFR Part 50, Appendix B 

program), the NRC divisions assigned to review the AMP should request that the Division 

responsible for quality assurance review the applicant’s proposal on a case-by-case basis.

3.0.1 Background on the Types of Reviews 

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

components (SSCs) identified in the scope of license renewal and subject to an AMR pursuant 

to 10 CRF 54.21(a)(1), that the effects of aging will be adequately managed so that the intended 

function(s) will be 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).

As stated in the GALL Report:

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

with guidance in reviewing a license renewal application. The GALL Report should be 

treated in the same manner as an approved topical report that is generically applicable. 

An applicant may reference the GALL Report in a license renewal application to 
NUREG-1800, Rev. 1 3.0-2 September 2005

demonstrate that the programs at the applicant’s facility correspond to those reviewed 

and approved in the GALL Report and that no further staff review is required, as 

described in the next paragraph. If the material presented in the GALL Report is 

applicable to the applicant’s facility, the staff should find the applicant’s reference to the 

GALL Report acceptable. In making this determination, the staff should consider whether 

the applicant has identified specific programs described and evaluated in the GALL 

Report. The staff, however, should not conduct a re-review of the substance of the 

matters described in the GALL Report. Rather, the staff should ensure that the applicant 

verifies that the approvals set forth in the GALL Report for generic programs apply to the 

applicant’s programs. The focus of the staff review should be on augmented programs 

for license renewal. The staff should also review information that is not addressed in the 

GALL Report or is otherwise different from that 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 on-site in an auditable form. The applicant should include a 

certification in the license renewal application that the verifications have been completed 

and are documented on-site 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 (require further evaluation) 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 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.
September 2005 3.0-3 NUREG-1800, Rev. 1

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 (line-items) in the AMR tables (in Chapters II through VIII of the GALL 

Report, Vol. II) establish the need to perform “further evaluations.” 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.

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 lineitem 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 

may make a commitment to augment the existing program to satisfy the GALL Report AMP 

element 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 those AMRs or AMPs that 

the applicant claims to be consistent with the GALL Report. An audit also includes technical 

assessments of exceptions or enhancements to the GALL Report AMP program elements.

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, and 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 should be 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
NUREG-1800, Rev. 1 3.0-4 September 2005

• 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.

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 a 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 perform 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 will complete these activities no later than the committed 

date. EPU impact on SSCs should be part of the license renewal review. If necessary, the PM 

will assign a responsible group to address EPU.
September 2005 3.1-1 NUREG-1800, Rev. 1

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 pressurizer relief tank, and the steam generators. 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. 1 3.1-2 September 2005

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 line-item and the associated LRA (licensee) AMP are consistent with 

the cited GALL Report AMR line-item. The reviewer should then confirm that the LRA AMR lineitem is consistent with the GALL Report AMR line-item to which it is compared.

For AMPs, 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 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 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 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.

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 apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.

3.1.2.2.1 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 shell assembly exposed to secondary feedwater and steam. Loss of 

material due to general, pitting, and crevice corrosion could also occur for the steel top head 

enclosure (without cladding) top head nozzles [vent, top head spray or reactor core isolation 
September 2005 3.1-3 NUREG-1800, Rev. 1

cooling (RCIC), and spare] exposed to reactor coolant. The existing program relies on 

control of reactor water chemistry to mitigate corrosion. However, control of water chemistry 

does not preclude loss of material due to pitting and crevice corrosion at locations of 

stagnant flow conditions. Therefore, the effectiveness of the chemistry control program 

should be verified to ensure that corrosion is not occurring. The GALL Report recommends 

further evaluation of programs to verify the effectiveness of the chemistry control program. A 

one-time inspection of select components at susceptible locations is an acceptable method 

to determine whether an aging effect is not occurring or an aging effect is progressing very 

slowly such that the component’s intended function will be maintained during the period of 

extended operation.

2. Loss of material due to pitting and crevice corrosion could occur in stainless steel BWR 

isolation condenser components exposed to reactor coolant. Loss of material due to 

general, pitting, and crevice corrosion could occur in steel BWR isolation condenser 

components. 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 chemistry control program should be verified to ensure that corrosion is 

not occurring. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of the chemistry control program. A one-time inspection of select components 

at susceptible locations is an acceptable method to determine whether an aging effect is not 

occurring or an aging effect is progressing very slowly such that the component’s intended 

function will be maintained during the period of extended operation.

3. Loss of material due to pitting and crevice corrosion could occur for stainless steel, nickel 

alloy, and steel with stainless steel or nickel alloy cladding flanges, nozzles, penetrations, 

pressure housings, safe ends, and vessel shells, heads and welds exposed to reactor 

coolant. 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 chemistry control program should be verified to ensure that corrosion is 

not occurring. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of the chemistry control program. A one-time inspection of select components 

at susceptible locations is an acceptable method to determine whether an aging effect is not 

occurring or an aging effect is progressing very slowly such that the component’s intended 

function will be maintained during the period of extended operation.

4. 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 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).
NUREG-1800, Rev. 1 3.1-4 September 2005

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. 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 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.

3.1.2.2.4 Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress 

Corrosion Cracking (IGSCC)

1. Cracking due to SCC and IGSCC could occur in the stainless steel and nickel alloy BWR top 

head enclosure vessel flange leak detection lines. The GALL Report recommends that a 

plant-specific AMP be evaluated because existing programs may not be capable of 

mitigating or detecting 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. 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 current well-established flaw evaluation 

procedure and criterion in the ASME Section XI Code. See the SRP-LR, Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analysis,” for generic guidance for meeting the requirements 
September 2005 3.1-5 NUREG-1800, Rev. 1

of 10 CFR 54.21(c).

3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void 

Swelling

Loss of fracture toughness due to neutron irradiation embrittlement and void swelling could 

occur in stainless steel and nickel alloy reactor vessel internals components exposed to reactor 

coolant and neutron flux. The GALL Report recommends no further aging management review if 

the applicant provides a commitment in the FSAR Supplement to (1) participate in the industry 

programs for investigating and managing aging effects on reactor internals; (2) evaluate and 

implement the results of the industry programs as applicable to the reactor internals; and (3) 

upon completion of these programs, but not less than 24 months before entering the period of 

extended operation, submit an inspection plan for reactor internals to the NRC for review and 

approval.

3.1.2.2.7 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 NUREG-0313 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). 

3.1.2.2.8 Cracking due to Cyclic Loading

1. Cracking due to cyclic loading could occur in the stainless steel BWR jet pump sensing 

lines. 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 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).
NUREG-1800, Rev. 1 3.1-6 September 2005

3.1.2.2.9 Loss of Preload due to Stress Relaxation

Loss of preload due to stress relaxation could occur in stainless steel and nickel alloy PWR

reactor vessel internals screws, bolts, tie rods, and hold-down springs exposed to reactor 

coolant. The GALL Report recommends no further aging management review if the applicant 

provides a commitment in the FSAR Supplement to (1) participate in the industry programs for 

investigating and managing aging effects on reactor internals; (2) evaluate and implement the 

results of the industry programs as applicable to the reactor internals; and (3) upon completion 

of these programs, but not less than 24 months before entering the period of extended 

operation, submit an inspection plan for reactor internals to the NRC for review and approval.

3.1.2.2.10 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).

3.1.2.2.11 Cracking due to Flow-Induced Vibration

Cracking due to flow-induced vibration could occur for the BWR stainless steel steam dryers

exposed to reactor coolant. 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).

3.1.2.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking (IASCC)

Cracking due to SCC and IASCC could occur in PWR stainless steel reactor internals exposed 

to reactor coolant. The existing program relies on control of water chemistry to mitigate these 

effects. The GALL Report recommends no further aging management review if the applicant 

provides a commitment in the FSAR Supplement to (1) participate in the industry programs for 

investigating and managing aging effects on reactor internals; (2) evaluate and implement the 

results of the industry programs as applicable to the reactor internals; and (3) upon completion 

of these programs, but not less than 24 months before entering the period of extended 

operation, submit an inspection plan for reactor internals to the NRC for review and approval.

3.1.2.2.13 Cracking due to Primary Water Stress Corrosion Cracking (PWSCC)

Cracking due to PWSCC could occur in PWR components made of nickel alloy and steel with 

nickel alloy cladding, including reactor coolant pressure boundary components and penetrations 

inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, and other internal 

components. With the exception of reactor vessel upper head nozzles and penetrations, the 

GALL Report recommends ASME Section XI ISI (for Class 1 components) and control of water 

chemistry. For nickel alloy components, no further aging management review is necessary if the 

applicant complies with applicable NRC Orders and provides a commitment in the FSAR 

supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted 

industry guidelines.
September 2005 3.1-7 NUREG-1800, Rev. 1

3.1.2.2.14 Wall Thinning due to Flow-Accelerated Corrosion

Wall thinning due to flow-accelerated corrosion could occur in steel feedwater inlet rings and 

supports. The GALL Report references NRC IN 91-19, "Steam Generator Feedwater 

Distribution Piping Damage," for evidence of flow accelerated corrosion in steam generators and 

recommends that a plant-specific AMP be evaluated because existing programs may not be 

capable of mitigating or detecting wall thinning due to flow-accelerated corrosion. Acceptance 

criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

3.1.2.2.15 Changes in Dimensions due to Void Swelling

Changes in dimensions due to void swelling could occur in stainless steel and nickel alloy PWR 

reactor internal components exposed to reactor coolant. The GALL Report recommends no 

further aging management review if the applicant provides a commitment in the FSAR 

Supplement to (1) participate in the industry programs for investigating and managing aging 

effects on reactor internals; (2) evaluate and implement the results of the industry programs as 

applicable to the reactor internals; and (3) upon completion of these programs, but not less than 

24 months before entering the period of extended operation, submit an inspection plan for 

reactor internals to the NRC for review and approval.

3.1.2.2.16 Cracking due to Stress Corrosion Cracking and Primary Water Stress 

Corrosion Cracking

1. Cracking due to SCC could occur on the primary coolant side of PWR steel steam generator 

upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with 

stainless steel. Cracking due to PWSCC could occur on the primary coolant side of PWR 

steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds

made or clad with nickel alloy. The GALL Report recommends ASME Section XI ISI and 

control of water chemistry to manage this aging and recommends no further aging 

management review for PWSCC of nickel alloy if the applicant complies with applicable 

NRC Orders and provides a commitment in the FSAR supplement to implement applicable 

(1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

2. Cracking due to SCC could occur on stainless steel pressurizer spray heads. Cracking due 

to PWSCC could occur on nickel-alloy pressurizer spray heads. The existing program relies 

on control of water chemistry to mitigate this aging effect. The GALL Report recommends 

one-time inspection to confirm that cracking is not occurring. For nickel alloy welded spray 

heads, the GALL Report recommends no further aging management review if the applicant 

complies with applicable NRC Orders and provide a commitment in the FSAR supplement to 

implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry 

guidelines.

3.1.2.2.17 Cracking due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

Cracking due to stress corrosion cracking (SCC), primary water stress corrosion cracking 

(PWSCC), and irradiation assisted stress corrosion cracking (IASCC) could occur in PWR 

stainless steel and nickel alloy reactor vessel internals components. The existing program relies 

on control of water chemistry to mitigate these effects. However, the existing program should be 

augmented to manage these aging effects for reactor vessel internals components. The GALL 

Report recommends no further aging management review if the applicant provides a 
NUREG-1800, Rev. 1 3.1-8 September 2005

commitment in the FSAR Supplement to (1) participate in the industry programs for investigating 

and managing aging effects on reactor internals; (2) evaluate and implement the results of the 

industry programs as applicable to the reactor internals; and (3) upon completion of these 

programs, but not less than 24 months before entering the period of extended operation, submit 

an inspection plan for reactor internals to the NRC for review and approval.

3.1.2.2.18 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 GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

3.1.2.4 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. Examples of the type of information to be included are provided in 

Table 3.1-2 of this SRP-LR.

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. 
September 2005 3.1-9 NUREG-1800, Rev. 1

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 with which the applicant is claiming to be consistent, 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 GALL 

Report pertinent to the reactor vessel, internals, and reactor coolant system are summarized in 

Table 3.1-1 of this SRP-LR. In this table, the ID column provides a row identifier useful in 

matching the information presented in the corresponding table in the GALL Report, Vol. 1. The 

Related Item column identifies the item number in the GALL Report, Vol. 2, Chapters II through 

VIII, presenting detailed information summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL Report AMR line-item to which the LRA AMR 

line-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 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. 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). 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 chemistry control program should be verified to ensure that corrosion is 
NUREG-1800, Rev. 1 3.1-10 September 2005

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 an augmented program for the management of loss of 

material due to pitting and crevice corrosion for stainless steel BWR isolation condenser 

components exposed to reactor coolant. The GALL Report also recommends an augmented 

program for the management of loss of material due to general, pitting, and crevice 

corrosion for steel BWR isolation condenser components. 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 chemistry control program 

should be verified to ensure that corrosion is not occurring. The reviewer verifies on a caseby-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.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for stainless steel, nickel alloy, and steel with 

stainless steel or nickel alloy cladding flanges, nozzles, penetrations, pressure housings, 

safe ends, and vessel shells, heads and welds exposed to reactor coolant to verify the 

effectiveness of the chemistry control program. A one-time inspection of select components 

at susceptible locations is an acceptable method to determine whether an aging effect is not 

occurring or an aging effect is progressing very slowly such that the component’s intended 

function will be maintained during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques. 

Follow-up actions are to be based on the inspection results.

4. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, and crevice corrosion for steel PWR steam generator upper 

and lower shell and transition cone exposed to secondary feedwater and steam. The 

existing program relies on control of reactor water chemistry to mitigate corrosion and on ISI 

for detection. Based on NRC IN 90-04, if general, pitting, and crevice corrosion of the shell 

exists, the existing program requirements may not be sufficient to detect loss of material due 

to these effects, and additional inspection procedures may be necessary. 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.
September 2005 3.1-11 NUREG-1800, Rev. 1

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 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. 

3.1.3.2.4 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.
NUREG-1800, Rev. 1 3.1-12 September 2005

3.1.3.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void 

Swelling 

The GALL Report recommends no further evaluation of programs to manage loss of fracture 

toughness due to neutron irradiation embrittlement and void swelling in stainless steel and

nickel alloy reactor vessel internals if the applicant provides a commitment in the FSAR 

Supplement to (1) participate in the industry programs for investigating and managing aging 

effects on reactor internals; (2) evaluate and implement the results of the industry programs as 

applicable to the reactor internals; and (3) upon completion of these programs, but not less than 

24 months before entering the period of extended operation, submit an inspection plan for 

reactor internals to the NRC for review and approval. The reviewer reviews the application to 

confirm the FSAR Supplement contains the appropriate commitment to ensure that an adequate 

program will be in place for the management of these aging effects. If the FSAR Supplement

does not contain the appropriate commitment, the staff 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 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 bottommounted instrument guide tubes exposed to reactor coolant. The reviewer reviews the 

applicant’s proposed program on a case-by-case basis to ensure that an adequate program 

will be in place for the management of these aging effects.

2. The GALL Report recommends that a plant-specific AMP be evaluated to manage cracking 

due to SCC in Class 1 CASS PWR 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. 

3.1.3.2.8 Cracking due to Cyclic Loading 

1. The GALL Report recommends that a plant specific AMP be evaluated for the management 

of cracking due to cyclic loading in stainless steel BWR jet pump sensing 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 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 caseby-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.
September 2005 3.1-13 NUREG-1800, Rev. 1

3.1.3.2.9 Loss of Preload due to Stress Relaxation 

The GALL Report recommends further evaluation of programs to manage loss of preload due to 

stress relaxation that could occur in stainless steel and nickel alloy reactor vessel internals 

screws, bolts, tie rods, and hold-down springs exposed to reactor coolant. The GALL Report

recommends no further aging management review if the applicant provides a commitment in the 

FSAR Supplement to (1) participate in the industry programs for investigating and managing 

aging effects on reactor internals; (2) evaluate and implement the results of the industry 

programs as applicable to the reactor internals; and (3) upon completion of these programs, but 

not less than 24 months before entering the period of extended operation, submit an inspection 

plan for reactor internals to the NRC for review and approval. The reviewer reviews the 

application to confirm the FSAR Supplement contains the appropriate commitment to ensure 

that an adequate program will be in place for the management of these aging effects. If the 

FSAR Supplement does not contain the appropriate commitment, the staff 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.

3.1.3.2.10 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.

3.1.3.2.11 Cracking due to Flow-Induced Vibration 

The GALL Report recommends further evaluation of a plant-specific AMP for the management 

of cracking due to flow-induced vibration of BWR stainless steel steam dryers. 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.

3.1.3.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking 

The GALL Report recommends further evaluation of programs to manage cracking due to SCC 

and IASCC in stainless steel reactor internal components exposed to reactor coolant. The GALL 

Report recommends no further aging management review if the applicant provides a 

commitment in the FSAR Supplement to (1) participate in the industry programs for investigating 

and managing aging effects on reactor internals; (2) evaluate and implement the results of the 

industry programs as applicable to the reactor internals; and (3) upon completion of these 

programs, but not less than 24 months before entering the period of extended operation, submit 

an inspection plan for reactor internals to the NRC for review and approval. 

The reviewer reviews the application to confirm the FSAR Supplement contains the appropriate 

commitment to ensure that an adequate program will be in place for the management of these 

aging effects. If the FSAR Supplement does not contain the appropriate commitment, the staff 

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. 1 3.1-14 September 2005

3.1.3.2.13 Cracking due to Primary Water Stress Corrosion Cracking 

For cracking due to PWSCC of PWR components (with the exception of reactor vessel upper 

head nozzles and penetrations) made of nickel alloy or having nickel alloy cladding, the GALL 

Report recommends no further aging management review if the applicant complies with 

applicable NRC Orders and provides a commitment in the FSAR Supplement to implement 

applicable (1) Bulletins and Generic Letters associated with nickel alloys and (2) staff-accepted 

industry guidelines. 

The reviewer reviews the application to confirm the FSAR Supplement contains the appropriate

commitment to ensure that an adequate program will be in place for the management of 

PWSCC. If the FSAR Supplement does not contain the appropriate commitment, the staff 

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 PWSCC. 

3.1.3.2.14 Wall Thinning due to Flow-accelerated Corrosion 

The GALL Report recommends that a plant-specific AMP be evaluated to manage loss of 

material due to wall thinning in the feedwater inlet ring and supports. Reference NRC IN 91-19, 

"Steam Generator Feedwater Distribution Piping Damage," for evidence of flow accelerated 

corrosion in steam generators. 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.

3.1.3.2.15 Changes in Dimensions due to Void Swelling

For changes in dimensions due to void swelling in stainless steel and nickel alloy reactor 

internal components, the GALL Report recommends no further aging management review if the 

applicant provides a commitment in the FSAR Supplement to (1) participate in the industry 

programs for investigating and managing aging effects on reactor internals; (2) evaluate and 

implement the results of the industry programs as applicable to the reactor internals; and (3) 

upon completion of these programs, but not less than 24 months before entering the period of 

extended operation, submit an inspection plan for reactor internals to the NRC for review and 

approval.

The reviewer reviews the application to confirm the FSAR Supplement contains the appropriate 

commitment to ensure that an adequate program will be in place for the management of this 

aging effect. If the FSAR Supplement does not contain the appropriate commitment, the staff 

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.

3.1.3.2.16 Cracking due to Stress Corrosion Cracking and Primary Water Stress

Corrosion Cracking

1. The GALL Report recommends ASME Section XI ISI and control of water chemistry to 

manage SCC and PWSCC on the primary coolant side of PWR steel steam generator 

upper and lower heads, tubesheets, and tube-to-tube sheet welds made or clad with 

stainless steel or nickel alloy. For cracking due to PWSCC of nickel-alloy-clad components, 

the GALL Report recommends no further aging management review if the applicant 

complies with applicable NRC Orders and provides a commitment in the FSAR Supplement

to implement applicable (1) Bulletins, and Generic Letters associated with nickel alloys and 
September 2005 3.1-15 NUREG-1800, Rev. 1

(2) staff-accepted industry guidelines. 

The reviewer reviews the application to confirm the FSAR Supplement contains the 

appropriate commitment to ensure that an adequate program will be in place for the 

management of PWSCC. If the FSAR Supplement does not contain the appropriate 

commitment, the staff 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 SCC and 

PWSCC. 

2. The GALL Report recommends control of water chemistry and a one-time inspection to 

manage cracking due to SCC of stainless steel pressurizer spray heads and PWSCC of

nickel alloy pressurizer spray heads. It recommends no further aging management review if 

the applicant complies with applicable NRC Orders and provide a commitment in the FSAR 

supplement to implement applicable (1) Bulletins and Generic Letters and (2) staffaccepted industry guidelines.

The reviewer reviews the application to confirm the FSAR Supplement contains the 

appropriate commitment to ensure that an adequate program will be in place for the 

management of PWSCC. If the FSAR Supplement does not contain the appropriate 

commitment, the staff 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 PWSCC. The 

reviewer verifies that the proposed one-time inspection will be performed using techniques 

similar to ASME Code and ASTM standards including visual, ultrasonic, and surface 

techniques to ensure that the component’s intended function will be maintained during the 

period of extended operation.

3.1.3.2.17 Cracking due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

The GALL Report recommends further evaluation of programs to manage cracking due to SCC, 

PWSCC, and IASCC in stainless steel and nickel alloy reactor vessel internals. The existing 

program relies on control of water chemistry to mitigate these effects. However, the existing 

program should be augmented to manage these aging effects for reactor vessel internals 

components. The GALL Report recommends no further aging management review if the 

applicant provides a commitment in the FSAR Supplement to (1) participate in the industry 

programs for investigating and managing aging effects on reactor internals; (2) evaluate and 

implement the results of the industry programs as applicable to the reactor internals; and (3) 

upon completion of these programs, but not less than 24 months before entering the period of 

extended operation, submit an inspection plan for reactor internals to the NRC for review and 

approval. 

The reviewer reviews the application to confirm the FSAR Supplement contains the appropriate 

commitment to ensure that an adequate program will be in place for the management of these 

aging effects. If the FSAR Supplement does not contain the appropriate commitment, the staff 

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.

3.1.3.2.18 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 
NUREG-1800, Rev. 1 3.1-16 September 2005

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 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in 

Table 3.1-2 in the FSAR Supplement for aging management of the reactor vessel, internals, and 

reactor coolant system for license renewal. The reviewer also confirms that the applicant has 

provided information equivalent to that in Table 3.1-2 in the FSAR Supplement for 

Subsection 3.1.3.3, “AMR Results Not Consistent with or Not Addressed in the GALL Report.”

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 3.1-2, 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 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). 
September 2005 3.1-17 NUREG-1800, Rev. 1

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, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.

3. NEI 97-06, “Steam Generator Program Guidelines,” Nuclear Energy Institute, December 

1997.

4. 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.

5. 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.

6. EPRI TR-107569-V1R5, “PWR Steam Generator Examination Guidelines, Rev. 5,” Electric 

Power Research Institute, September 1997.

7. NRC Regulatory Guide 1.83, “Inservice Inspection of Pressurized Water Reactor Steam 

Generator Tubes,” U.S. Nuclear Regulatory Commission, June 1974.

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.
NUREG-1800, Rev. 1 3.1-18 September 2005

13. NSAC-202L-R2, “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. NRC Generic Letter 97-06, “Degradation of Steam Generator Internals,” U.S. Nuclear 

Regulatory Commission, December 30, 1997.

16. BWRVIP-29 (EPRI TR-103515), BWR Water Chemistry Guidelines-Revision 3, Normal and 

Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 

1994.

17. 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.

18. EPRI TR-105714, PWR primary Water Chemistry Guidelines-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, Nov. 1995.

19. NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel 

Piping, January 25, 1988.

20. NRC Generic Letter 97-01, Degradation of Control Rod Drive Mechanism Nozzle and Other 

Vessel Closure Head Penetrations, April 1, 1997.

21. NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, July 9, 

1997.

22. NRC Regulatory Guide 1.99, Rev. 2, Radiation Embrittlement of Reactor Vessel Materials,

May 1988.

23. NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle 

Cracking, U.S. Nuclear Regulatory Commission, November 1980.

24. 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.

25. EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, Palo Alto, CA, December 1995.

26. NEI letter dated Dec. 11, 1998, Dave Modeen to Gus Lainas, “Responses to NRC 

Requests for Additional Information (RAIs) on GL 97-01.”

27. EPRI TR-102134, PWR Secondary Water Chemistry Guideline-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, May 1993.

28. NRC Information Notice 91-19, Steam Generator Feedwater Distribution Piping Damage, 

March 12, 1991.
September 2005 3.1-19 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

1 BWR Steel pressure vessel support skirt and 

attachment welds

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-70

2 BWR Steel; stainless steel; steel with nickelalloy or stainless steel cladding; nickelalloy reactor vessel components: 

flanges; nozzles; penetrations; safe 

ends; thermal sleeves; vessel shells, 

heads and welds

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) and environmental 

effects are to be addressed 

for Class 1 components

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-04

3 BWR Steel; stainless steel; steel with nickelalloy or stainless steel cladding; nickelalloy reactor coolant pressure boundary 

piping, piping components, and piping 

elements exposed to reactor coolant

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) and environmental 

effects are to be addressed 

for Class 1 components

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-220

4 BWR Steel pump and valve closure bolting Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) check Code limits 

for allowable cycles (less 

than 7000 cycles) of thermal 

stress range

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-28

5 BWR/ 

PWR

Stainless steel and nickel alloy reactor 

vessel internals components

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-53

6 PWR Nickel Alloy tubes and sleeves in a 

reactor coolant and secondary 

feedwater/steam environment

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-46
NUREG-1800, Rev. 1 3.1-20 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

7 PWR Steel and stainless steel reactor coolant 

pressure boundary closure bolting, head 

closure studs, support skirts and 

attachment welds, pressurizer relief tank 

components, steam generator 

components, piping and components 

external surfaces and bolting

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-13

R-18

R-33

R-73

8 PWR Steel; stainless steel; and nickel-alloy 

reactor coolant pressure boundary 

piping, piping components, piping 

elements; flanges; nozzles and safe 

ends; pressurizer vessel shell heads and 

welds; heater sheaths and sleeves; 

penetrations; and thermal sleeves

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) and environmental 

effects are to be addressed 

for Class 1 components

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-223

9 PWR Steel; stainless steel; steel with nickelalloy or stainless steel cladding; nickelalloy reactor vessel components: 

flanges; nozzles; penetrations; pressure 

housings; safe ends; thermal sleeves; 

vessel shells, heads and welds

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) and environmental 

effects are to be addressed 

for Class 1 components

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-219

10 PWR Steel; stainless steel; steel with nickelalloy or stainless steel cladding; nickelalloy steam generator components 

(flanges; penetrations; nozzles; safe 

ends, lower heads and welds)

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c) and environmental 

effects are to be addressed 

for Class 1 components

Yes, TLAA (See 

subsection 

3.1.2.2.1)

R-221

R-222

11 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

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.2.1)

R-59
September 2005 3.1-21 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

12 PWR Steel steam generator shell assembly 

exposed to secondary feedwater and 

steam

Loss of material due to 

general, pitting and 

crevice corrosion

Water Chemistry and OneTime InspectionYes, detection of

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.2.1)

R-224

13 BWR Steel and stainless steel isolation 

condenser components exposed to 

reactor coolant

Loss of material due to 

general (steel only), 

pitting and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.2.2)

R-16

14 BWR Stainless steel, nickel-alloy, and steel 

with nickel-alloy or stainless steel 

cladding reactor vessel flanges, nozzles, 

penetrations, safe ends, vessel shells, 

heads and welds

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.2.3)

RP-25

15 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

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to

be evaluated (See 

subsection 

3.1.2.2.2.3)

RP-27

16 PWR Steel steam generator upper and lower 

shell and transition cone exposed to 

secondary feedwater and steam

Loss of material due to 

general, pitting and 

crevice corrosion

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry and, for 

Westinghouse Model 44 and 

51 S/G, if general and pitting 

corrosion of the shell is 

known to exist, additional 

inspection procedures are to 

be developed. 

Yes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.2.4)

R-34
NUREG-1800, Rev. 1 3.1-22 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

17 BWR/ 

PWR

Steel (with or without stainless steel 

cladding) reactor vessel beltline shell, 

nozzles, and welds

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement

TLAA, evaluated in 

accordance with Appendix G 

of 10 CFR Part 50 and RG 

1.99. The applicant may 

choose to demonstrate that 

the materials of the nozzles 

are not controlling for the 

TLAA evaluations.

Yes, TLAA (See 

subsection 

3.1.2.2.3.1)

R-62

R-67

R-81

R-84

18 BWR/ 

PWR

Steel (with or without stainless steel 

cladding) reactor vessel beltline shell, 

nozzles, and welds; safety injection 

nozzles

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement

Reactor Vessel Surveillance Yes, plant specific 

(See subsection 

3.1.2.2.3.2)

R-63

R-82

R-86

19 BWR Stainless steel and nickel alloy top head 

enclosure vessel flange leak detection 

line 

Cracking due to stress 

corrosion cracking and 

intergranular stress 

corrosion cracking

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.1.2.2.4.1) 

R-61

20 BWR Stainless steel isolation condenser 

components exposed to reactor coolant

Cracking due to stress 

corrosion cracking and 

intergranular stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD), Water 

Chemistry, and plant-specific 

verification program

Yes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.4.2)

R-15

21 PWR Reactor vessel shell fabricated of 

SA508-Cl 2 forgings clad with stainless 

steel using a high-heat-input welding 

process

Crack growth due to 

cyclic loading

TLAA Yes, TLAA (See 

subsection 

3.1.2.2.5) 

R-85
September 2005 3.1-23 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

22 PWR Stainless steel and nickel alloy reactor 

vessel internals components exposed to 

reactor coolant and neutron flux

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement, void 

swelling

FSAR supplement 

commitment to (1) 

participate in industry RVI 

aging programs (2) 

implement applicable results 

(3) submit for NRC approval 

> 24 months before the 

extended period an RVI 

inspection plan based on 

industry recommendation.

No, but licensee 

commitment to be 

confirmed (See 

subsection 

3.1.2.2.6)

R-122

R-127

R-128

R-132

R-135

R-141

R-157

R-161

R-164

R-169

R-178

R-188

R-196

R-205

R-212

R-216

23 PWR Stainless steel reactor vessel closure 

head flange leak detection line and 

bottom-mounted instrument guide tubes

Cracking due to stress 

corrosion cracking

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.1.2.2.7.1) 

R-74

RP-13

24 PWR Class 1 cast austenitic stainless steel 

piping, piping components, and piping 

elements exposed to reactor coolant

Cracking due to stress 

corrosion cracking

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 

3.1.2.2.7.2)

R-05

25 BWR Stainless steel jet pump sensing line Cracking due to cyclic 

loading

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.1.2.2.8.1) 

R-102

26 BWR Steel and stainless steel isolation 

condenser components exposed to 

reactor coolant

Cracking due to cyclic 

loading

Inservice Inspection (IWB, 

IWC, and IWD) and plantspecific verification program

Yes, detection of 

aging effects is to 

be evaluated (See 

subsection 

3.1.2.2.8.2)

R-225
NUREG-1800, Rev. 1 3.1-24 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

27 PWR Stainless steel and nickel alloy reactor 

vessel internals screws, bolts, tie rods, 

and hold-down springs

Loss of preload due to 

stress relaxation

FSAR supplement 

commitment to (1) 

participate in industry RVI 

aging programs (2) 

implement applicable results 

(3) submit for NRC approval 

> 24 months before the 

extended period an RVI 

inspection plan based on 

industry recommendation.

No, but licensee 

commitment to be 

confirmed (See 

subsection 

3.1.2.2.9)

R-108

R-114

R-129

R-136

R-137

R-154

R-165

R-184

R-192

R-197

R-201

R-207

R-213

28 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 

3.1.2.2.10) 

R-39

29 BWR Stainless steel steam dryers exposed to 

reactor coolant

Cracking due to flowinduced vibrationA plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.1.2.2.11) 

RP-18
September 2005 3.1-25 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

30 PWR Stainless steel reactor vessel internals 

components (e.g., Upper internals 

assembly, RCCA guide tube assemblies, 

Baffle/former assembly, Lower internal 

assembly, shroud assemblies, Plenum 

cover and plenum cylinder, Upper grid 

assembly, Control rod guide tube 

(CRGT) assembly, Core support shield 

assembly, Core barrel assembly, Lower 

grid assembly, Flow distributor assembly, 

Thermal shield, Instrumentation support 

structures)

Cracking due to stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Water Chemistry and FSAR 

supplement commitment to 

(1) participate in industry RVI 

aging programs (2) 

implement applicable results 

(3) submit for NRC approval 

> 24 months before the 

extended period an RVI 

inspection plan based on 

industry recommendation.

No, but licensee 

commitment 

needs to be 

confirmed (See 

subsection 

3.1.2.2.12)

R-106

R-109

R-116

R-120

R-123

R-125

R-138

R-143

R-146

R-149

R-155

R-159

R-166

R-172

R-173

R-175

R-176

R-180

R-181

R-185

R-193

R-202

R-209

R-214
NUREG-1800, Rev. 1 3.1-26 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

31 PWR Nickel alloy and steel with nickel-alloy 

cladding piping, piping component, 

piping elements, penetrations, nozzles, 

safe ends, and welds (other than reactor 

vessel head); pressurizer heater 

sheaths, sleeves, diaphragm plate, 

manways and flanges; core support 

pads/core guide lugs

Cracking due to primary 

water stress corrosion 

cracking

Inservice Inspection (IWB, 

IWC, and IWD) and Water 

Chemistry and for nickel 

alloy, comply with applicable 

NRC Orders and provide a 

commitment in the FSAR 

supplement to implement 

applicable (1) Bulletins and 

Generic Letters and (2) staffaccepted industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed (See

subsection 

3.1.2.2.13)

R-01

R-06

R-88

R-89

RP-22

RP-31

32 PWR Steel steam generator feedwater inlet 

ring and supports

Wall thinning due to 

flow-accelerated 

corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.1.2.2.14)

R-51
September 2005 3.1-27 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

33 PWR Stainless steel and nickel alloy reactor 

vessel internals components

Changes in dimensions 

due to void swelling

FSAR supplement 

commitment to (1) 

participate in industry RVI 

aging programs (2) 

implement applicable results 

(3) submit for NRC approval 

> 24 months before the 

extended period an RVI 

inspection plan based on 

industry recommendation.

No, but licensee 

commitment to be 

confirmed (See 

subsection 

3.1.2.2.15)

R-107

R-110

R-113

R-117

R-119

R-121

R-124

R-126

R-131

R-134

R-139

R-144

R-147

R-151

R-158

R-160

R-163

R-168

R-174

R-177

R-182

R-187

R-195

R-199

R-204

R-211

R-215
NUREG-1800, Rev. 1 3.1-28 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

34 PWR Stainless steel and nickel alloy reactor 

control rod drive head penetration 

pressure housings 

Cracking due to stress 

corrosion cracking and 

primary water stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD) and Water 

Chemistry and for nickel 

alloy, comply with applicable 

NRC Orders and provide a 

commitment in the FSAR 

supplement to implement 

applicable (1) Bulletins and 

Generic Letters and (2) staffaccepted industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed (See 

subsection 

3.1.2.2.16.1)

R-76

35 PWR Steel with stainless steel or nickel alloy 

cladding primary side components; 

steam generator upper and lower heads, 

tubesheets and tube-to-tube sheet welds

Cracking due to stress 

corrosion cracking and 

primary water stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD) and Water 

Chemistry and for nickel 

alloy, comply with applicable 

NRC Orders and provide a 

commitment in the FSAR 

supplement to implement 

applicable (1) Bulletins and 

Generic Letters and (2) staffaccepted industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed (See 

subsection 

3.1.2.2.16.1)

R-35

36 PWR Nickel alloy, stainless steel pressurizer 

spray head

Cracking due to stress 

corrosion cracking and 

primary water stress 

corrosion cracking

Water Chemistry and OneTime Inspection and, for 

nickel alloy welded spray 

heads, comply with 

applicable NRC Orders and 

provide a commitment in the 

FSAR supplement to 

implement applicable (1) 

Bulletins and Generic Letters 

and (2) staff-accepted 

industry guidelines.

No, unless 

licensee 

commitment 

needs to be 

confirmed (See 

subsection 

3.1.2.2.16.2)

R-24
September 2005 3.1-29 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

37 PWR Stainless steel and nickel alloy reactor 

vessel internals components (e.g., Upper 

internals assembly, RCCA guide tube 

assemblies, Lower internal assembly, 

CEA shroud assemblies, Core shroud 

assembly, Core support shield assembly, 

Core barrel assembly, Lower grid 

assembly, Flow distributor assembly)

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Water Chemistry and FSAR 

supplement commitment to 

(1) participate in industry RVI 

aging programs (2) 

implement applicable results 

(3) submit for NRC approval 

> 24 months before the 

extended period an RVI 

inspection plan based on 

industry recommendation.

No, but licensee 

commitment 

needs to be 

confirmed (See 

subsection 

3.1.2.2.17)

R-112

R-118

R-130

R-133

R-150

R-162

R-167

R-186

R-194

R-203

R-210

38 BWR Steel (with or without stainless steel 

cladding) control rod drive return line 

nozzles exposed to reactor coolant

Cracking due to cyclic 

loading

BWR CR Drive Return Line 

Nozzle

No R-66

39 BWR Steel (with or without stainless steel 

cladding) feedwater nozzles exposed to 

reactor coolant

Cracking due to cyclic 

loading

BWR Feedwater Nozzle No R-65

40 BWR Stainless steel and nickel alloy 

penetrations for control rod drive stub 

tubes instrumentation, jet pump 

instrument, standby liquid control, flux 

monitor, and drain line exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking, 

Intergranular stress 

corrosion cracking, cyclic 

loading

BWR Penetrations and 

Water Chemistry

No R-69

41 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 and 

intergranular stress 

corrosion cracking

BWR Stress Corrosion 

Cracking and Water 

Chemistry

No R-20

R-21

R-68

42 BWR Stainless steel and nickel alloy vessel 

shell attachment welds exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking and 

intergranular stress 

corrosion cracking

BWR Vessel ID Attachment 

Welds and Water Chemistry 

No R-64
NUREG-1800, Rev. 1 3.1-30 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

43 BWR Stainless steel fuel supports and control 

rod drive assemblies control rod drive 

housing exposed to reactor coolant

Cracking due to stress 

corrosion cracking and 

intergranular stress 

corrosion cracking

BWR Vessel Internals and 

Water Chemistry

No R-104

44 BWR Stainless steel and nickel alloy core 

shroud, core plate, core plate bolts, 

support structure, top guide, core spray 

lines, spargers, jet pump assemblies, 

control rod drive housing, nuclear 

instrumentation guide tubes 

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

BWR Vessel Internals and 

Water Chemistry

No R-92

R-93

R-96

R-97

R-98

R-99

R-100

R-105

45 BWR Steel piping, piping components, and 

piping elements exposed to reactor 

coolant

Wall thinning due to 

flow-accelerated 

corrosion

Flow-Accelerated Corrosion No R-23

46 BWR Nickel alloy core shroud and core plate 

access hole cover (mechanical covers)

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry

No R-95

47 BWR Stainless steel and nickel-alloy reactor 

vessel internals exposed to reactor 

coolant

Loss of material due to 

pitting and crevice 

corrosion

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry

No RP-26

48 BWR Steel and stainless steel 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 and mechanical 

loading

Inservice Inspection (IWB, 

IWC, and IWD), Water 

chemistry, and One-Time 

Inspection of ASME Code 

Class 1 Small-bore Piping

No R-03
September 2005 3.1-31 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

49 BWR Nickel alloy core shroud and core plate 

access hole cover (welded covers)

Cracking due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD), Water 

Chemistry, and, for BWRs 

with a crevice in the access 

hole covers, augmented 

inspection using UT or other 

demonstrated acceptable 

inspection of the access hole 

cover welds

No R-94

50 BWR High-strength low alloy steel top head 

closure studs and nuts exposed to air 

with reactor coolant leakage

Cracking due to stress 

corrosion cracking and 

intergranular stress 

corrosion cracking

Reactor Head Closure Studs No R-60

51 BWR Cast austenitic stainless steel jet pump 

assembly castings; orificed fuel support 

Loss of fracture 

toughness due to 

thermal aging and 

neutron irradiation 

embrittlement

Thermal Aging and Neutron 

Irradiation Embrittlement of 

CASS

No R-101

R-103

52 BWR/ 

PWR

Steel and stainless steel reactor coolant 

pressure boundary (RCPB) pump and 

valve closure bolting, manway and 

holding bolting, flange bolting, and 

closure bolting in high-pressure and 

high-temperature systems 

Cracking due to stress 

corrosion cracking, loss 

of material due to wear, 

loss of preload due to 

thermal effects, gasket 

creep, and selfloosening

Bolting Integrity No R-10

R-11

R-12

R-26

R-27

R-29

R-32

R-78

R-79

R-80

53 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

Closed-Cycle Cooling Water 

System

No RP-10
NUREG-1800, Rev. 1 3.1-32 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

54 BWR/ 

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

Closed-Cycle Cooling Water 

System

No RP-11

55 BWR/ 

PWR

Cast austenitic stainless steel Class 1 

pump casings, and valve bodies and 

bonnets exposed to reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Inservice inspection (IWB, 

IWC, and IWD). Thermal 

aging susceptibility 

screening is not necessary, 

inservice inspection 

requirements are sufficient 

for managing these aging 

effects. ASME Code Case 

N-481 also provides an 

alternative for pump casings.

No R-08

56 BWR/ 

PWR

Copper alloy >15% Zn piping, piping 

components, and piping elements 

exposed to closed cycle cooling water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No RP-12

57 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°C (>482°F)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Thermal Aging 

Embrittlement of CASS

No R-52

R-77

58 PWR Steel reactor coolant pressure boundary 

external surfaces exposed to air with 

borated water leakage

Loss of material due to 

Boric acid corrosion

Boric Acid Corrosion No R-17

59 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

Flow-Accelerated Corrosion No R-37

R-38

60 PWR Stainless steel flux thimble tubes (with or 

without chrome plating)

Loss of material due to 

Wear

Flux Thimble Tube 

Inspection

No R-145
September 2005 3.1-33 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

61 PWR Stainless steel, steel pressurizer integral 

support exposed to air with metal 

temperature up to 288°C (550°F)

Cracking due to cyclic 

loading

Inservice Inspection (IWB, 

IWC, and IWD)

No R-19

62 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

Inservice Inspection (IWB, 

IWC, and IWD)

No R-56

63 PWR Steel reactor vessel flange, stainless 

steel and nickel alloy reactor vessel 

internals exposed to reactor coolant 

(e.g., upper and lower internals 

assembly, CEA shroud assembly, core 

support barrel, upper grid assembly, core 

support shield assembly, lower grid 

assembly)

Loss of material due to 

Wear

Inservice Inspection (IWB, 

IWC, and IWD)

No R-87

R-115

R-142

R-148

R-152

R-156

R-170

R-179

R-190

R-208

64 PWR Stainless steel and steel with stainless 

steel or nickel alloy cladding pressurizer 

components

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD) and Water 

Chemistry

No R-25

65 PWR Nickel alloy reactor vessel upper head 

and control rod drive penetration 

nozzles, instrument tubes, head vent 

pipe (top head), and welds 

Cracking due to primary 

water stress corrosion 

cracking

Inservice Inspection (IWB, 

IWC, and IWD) and Water 

Chemistry and Nickel-Alloy 

Penetration Nozzles Welded 

to the Upper Reactor Vessel 

Closure Heads of 

Pressurized Water Reactors

No R-75

R-90
NUREG-1800, Rev. 1 3.1-34 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

66 PWR Steel steam generator secondary 

manways and handholds (cover only) 

exposed to air with leaking secondaryside water and/or steam

Loss of material due to 

erosion

Inservice Inspection (IWB, 

IWC, and IWD) for Class 2 

components

No R-31

67 PWR Steel with stainless steel or nickel alloy 

cladding; or stainless steel pressurizer 

components exposed to reactor coolant

Cracking due to cyclic 

loading

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry

No R-58

68 PWR Stainless steel, steel with stainless steel 

cladding Class 1 piping, fittings, pump 

casings, valve bodies, nozzles, safe 

ends, manways, flanges, CRD housing; 

pressurizer heater sheaths, sleeves, 

diaphragm plate; pressurizer relief tank 

components, reactor coolant system cold 

leg, hot leg, surge line, and spray line 

piping and fittings

Cracking due to stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry

No R-07

R-09

R-14

R-30

R-217

69 PWR Stainless steel, nickel alloy safety 

injection nozzles, safe ends, and 

associated welds and buttering exposed 

to reactor coolant

Cracking due to stress 

corrosion cracking, 

primary water stress 

corrosion cracking

Inservice Inspection (IWB, 

IWC, and IWD), and Water 

Chemistry

No R-83

70 PWR Stainless steel; steel with stainless steel 

cladding Class 1 piping, fittings and 

branch connections < NPS 4 exposed to 

reactor coolant

Cracking due to stress 

corrosion cracking, 

thermal and mechanical 

loading

Inservice Inspection (IWB, 

IWC, and IWD), Water 

chemistry, and One-Time 

Inspection of ASME Code 

Class 1 Small-bore Piping

No R-02

71 PWR High-strength low alloy steel closure 

head stud assembly exposed to air with 

reactor coolant leakage

Cracking due to stress 

corrosion cracking; loss 

of material due to wear

Reactor Head Closure Studs No R-71

R-72
September 2005 3.1-35 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

72 PWR Nickel alloy steam generator tubes and 

sleeves exposed to secondary 

feedwater/ steam

Cracking due to OD 

stress corrosion cracking 

and intergranular attack, 

loss of material due to 

fretting and wear

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-47

R-48

R-49

73 PWR Nickel alloy steam generator tubes, 

repair sleeves, and tube plugs exposed 

to reactor coolant

Cracking due to primary 

water stress corrosion 

cracking

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-40

R-44

74 PWR Chrome plated steel, stainless steel, 

nickel alloy steam generator antivibration bars exposed to secondary 

feedwater/ steam

Cracking due to stress

corrosion cracking, loss 

of material due to 

crevice corrosion and 

fretting

Steam Generator Tube 

Integrity and Water 

Chemistry

No RP-14

RP-15

75 PWR Nickel alloy once-through steam 

generator tubes exposed to secondary 

feedwater/ steam

Denting due to corrosion 

of carbon steel tube 

support plate

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-226

76 PWR Steel steam generator tube support 

plate, tube bundle wrapper exposed to 

secondary feedwater/steam

Loss of material due to 

erosion, general, pitting, 

and crevice corrosion, 

ligament cracking due to 

corrosion

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-42

RP-16

77 PWR Nickel alloy steam generator tubes and 

sleeves exposed to phosphate chemistry 

in secondary feedwater/ steam

Loss of material due to 

wastage and pitting 

corrosion

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-50

78 PWR Steel steam generator tube support 

lattice bars exposed to secondary 

feedwater/ steam

Wall thinning due to 

flow-accelerated 

corrosion

Steam Generator Tube 

Integrity and Water 

Chemistry

No R-41
NUREG-1800, Rev. 1 3.1-36 September 2005

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

79 PWR Nickel alloy steam generator tubes 

exposed to secondary feedwater/ steam

Denting due to corrosion 

of steel tube support 

plate

Steam Generator Tube 

Integrity; Water Chemistry 

and, for plants that could 

experience denting at the 

upper support plates, 

evaluate potential for rapidly 

propagating cracks and then 

develop and take corrective 

actions consistent with 

Bulletin 88-02.

No R-43

80 PWR Cast austenitic stainless steel reactor 

vessel internals (e.g., upper internals 

assembly, lower internal assembly, CEA 

shroud assemblies, control rod guide 

tube assembly, core support shield 

assembly, lower grid assembly)

Loss of fracture 

toughness due to 

thermal aging and 

neutron irradiation 

embrittlement

Thermal Aging and Neutron 

Irradiation Embrittlement of 

CASS

No R-111

R-140

R-153

R-171

R-183

R-191

R-206

81 PWR Nickel alloy or nickel-alloy clad steam 

generator divider plate exposed to 

reactor coolant

Cracking due to primary 

water stress corrosion 

cracking

Water Chemistry No RP-21

82 PWR Stainless steel steam generator primary 

side divider plate exposed to reactor 

coolant

Cracking due to stress 

corrosion cracking

Water Chemistry No RP-17

83 PWR Stainless steel; steel with nickel-alloy or 

stainless steel cladding; and nickel-alloy 

reactor vessel internals and reactor 

coolant pressure boundary components 

exposed to reactor coolant

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry No RP-23

RP-24

RP-28
September 2005 3.1-37 NUREG-1800, Rev. 1

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

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended

Related 

Item

84 PWR Nickel alloy steam generator 

components such as, secondary side 

nozzles (vent, drain, and 

instrumentation) exposed to secondary 

feedwater/ steam

Cracking due to stress 

corrosion cracking

Water Chemistry and OneTime Inspection or Inservice 

Inspection (IWB, IWC, and 

IWD). 

No R-36

85 BWR/ 

PWR

Nickel alloy piping, piping components, 

and piping elements exposed to air –

indoor uncontrolled (external)

None None NA - No AEM or 

AMP

RP-03

86 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to air – indoor uncontrolled 

(External); air with borated water 

leakage; concrete; gas

None None NA - No AEM or 

AMP

RP-04

RP-05

RP-06

RP-07

87 BWR/ 

PWR

Steel piping, piping components, and 

piping elements in concrete

None None NA - No AEM or 

AMP

RP-01
NUREG-1800, Rev. 1 3.1-38 September 2005

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD

The program consists of periodic volumetric, 

surface, and/or visual examination of 

components and their supports for assessment, 

signs of degradation, and corrective actions. 

This program is in accordance with ASME 

Section XI, 1995 edition through the 1996 

addenda. 

Existing program

Bolting Integrity This program relies on recommendations for a 

comprehensive bolting integrity program, as 

delineated in NUREG-1339, and industry 

recommendations, as delineated in the Electric 

Power Research Institute (EPRI) NP-5769, with 

the exceptions noted in NUREG-1339 for 

safety-related bolting. The program relies on 

industry recommendations for a comprehensive 

bolting maintenance, as delineated in the EPRI 

TR-104213 for pressure retaining bolting and 

structural bolting. The program generally 

includes periodic inspection of closure bolting 

for indication 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. Other aging management programs, 

such as XI.M1, “ASME Section XI Inservice 

Inspection (ISI) Subsections IWB, IWC, and 

IWD” and XI.S3, “ASME Section XI Subsection 

IWF” also manage inspection of safety-related 

bolting and supplement this bolting integrity 

program. This program covers bolting within the 

scope of license renewal, including:1) safetyrelated bolting, 2) bolting for nuclear steam 

supply system (NSSS) component supports, 3) 

bolting for other pressure retaining components, 

including non-safety-related bolting, and 4) 

structural bolting. (actual measured yield 

strength > 150 ksi).

Existing program

Boric Acid Corrosion The program consists of (1) visual inspection of 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of 

leak path and removal of the boric acid 

residues, (3) assessment of the damage, and 

(4) follow-up inspection for adequacy. This 

program is implemented in response to 

GL 88-05 and recent operating experience.

Existing program
September 2005 3.1-39 NUREG-1800, Rev. 1

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

BWR Control Rod 

Drive Return Line 

Nozzle

The program monitors the effects of cracking on 

the intended function of the component by 

detection and sizing of cracks by ISI in 

accordance with the NUREG-0619 and 

alternative recommendation of GE NE-523-A71-

0594. NUREG-0619 specifies UT of the entire 

nozzle and penetration testing (PT) of varying 

portions of the blend radius and bore. 

GE NE-523-A71-0594 specifies UT of specific 

regions of the blend radius and bore. UT 

techniques and personnel qualification are 

according to the guidelines of GE NE-523-A71-

0594. 

Program should be 

implemented before 

the period of 

extended operation.

BWR Feedwater 

Nozzle

This program includes (a) enhancing inservice 

inspection (ISI) specified in the American 

Society of Mechanical Engineers (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

BWR Penetrations The program includes (a) inspection and flaw 

evaluation in conformance with the guidelines of 

staff-approved boiling water reactor vessel and 

internals project (BWRVIP)-49 and 

BWRVIP-27 documents and (b) monitoring and 

control of reactor coolant water chemistry in 

accordance with the guidelines of BWRVIP-29 

(EPRI TR-103515) to ensure the long-term 

integrity and safe operation of boiling water 

reactor (BWR) vessel internal components. 

Existing program

BWR Stress 

Corrosion Cracking

The program to manage intergranular stress 

corrosion cracking (IGSCC) in boiling water 

reactor (BWR) coolant pressure boundary 

piping made of stainless steel (SS) is delineated 

in NUREG-0313, Rev. 2, and Nuclear 

Regulatory Commission (NRC) Generic Letter 

(GL) 88-01 and its Supplement 1. The program 

includes (a) preventive measures to mitigate 

IGSCC and (b) inspections to monitor IGSCC 

and its effects.

Existing program

BWR Vessel ID 

Attachment Welds

The program includes (a) inspection and flaw 

evaluation in conformance with the guidelines 

of staff-approved boiling water reactor vessel 

and internals project (BWRVIP) -48 and 

(b) monitoring and control of reactor coolant 

water chemistry in accordance with the 

guidelines of BWRVIP-29 (EPRI TR-103515). 

Existing program
NUREG-1800, Rev. 1 3.1-40 September 2005

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

BWR Vessel 

Internals 

The program includes (a) inspection and flaw 

evaluation in conformance with the guidelines of 

applicable and staff-approved boiling water 

reactor vessel and internals project (BWRVIP) 

documents and (b) monitoring and control of 

reactor coolant water chemistry in accordance 

with the guidelines of BWRVIP-29 (EPRI 

TR-103515) to ensure the long-term integrity 

and safe operation of boiling water reactor 

(BWR) vessel internal components.

Existing program

Closed-Cycle

Cooling Water 

System 

The program relies on preventive measures to 

minimize corrosion and SCC by maintaining 

inhibitors and by performing non-chemistry 

monitoring consisting of inspection and 

nondestructive evaluations based on the 

guidelines of EPRI-TR-107396 for closed–cycle 

cooling water systems.

Flow-Accelerated 

Corrosion 

The program consists of the following: 

(1) conduct appropriate analysis and baseline 

inspection, (2) determine extent of thinning and 

replace/repair components, and (3) perform 

follow up inspections to confirm or quantify and 

take longer-term corrective actions. This 

program is in response to NRC GL 89-08.

Existing program

Flux Thimble Tube 

Inspection

This inspection program is used to monitor for 

thinning of the flux thimble tube walls, which 

provide a path for the incore neutron flux 

monitoring system detectors and which form 

part of the reactor coolant pressure boundary. 

This program implements the recommendations 

of NRC Bulletin 88 09, "Thimble Tube Thinning 

in Westinghouse Reactors.” The program 

includes: (1) specific augmented inspections 

using eddy current testing or other applicantjustified and NRC-accepted inspection 

techniques for detecting wear in flux detector 

thimble tubes, (2) bases for establishing a baseline monitoring frequency for the augmented 

examinations of the flux detector thimble tubes

based on the applicant’s response to NRC 

Bulletin 88-09 and bases for amending the 

monitoring frequency based on actual plantspecific thimble tube wear rate results, (3) 

specific flaw evaluation acceptance criteria to 

be used if loss of material by wear is detected in 

the flux detector thimble tubes and (4) specific 

corrective actions to be taken if the acceptance 

criteria for detected indications are exceeded.

Existing Program
September 2005 3.1-41 NUREG-1800, Rev. 1

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

Reactor Vessel 

Closure Heads of 

Pressurized Water 

Reactors

This program is established to ensure that 

augmented inservice inspections (ISI) of all 

nickel-alloy vessel head penetration (VHP) 

nozzles welded to the upper reactor vessel (RV) 

head of a PWR-designed light-water reactor will 

continue to be performed as mandated by the 

interim requirements in Order EA-03-009, 

“Issuance of Order Establishing Interim 

Inspection Requirements for Reactor Pressure 

Vessel Heads at Pressurized Water Reactors,” 

as amended by the First Revision of the Order, 

or by any subsequent NRC requirements that 

may be established to supersede the 

requirements of Order EA-03-009. The program 

is focused on managing the effects of cracking 

due to PWSCC of the nickel-alloy used in the 

fabrication of the upper VHP nozzles at PWRdesigned nuclear facilities. The scope of this 

AMP is limited to upper VHP nozzles, including 

control rod drive mechanism (CRDM) nozzles, 

control element drive mechanism (CEDM) 

nozzles, thermocouples (TC) nozzles, in-core 

instrumentation (ICI) nozzles, and vent line 

nozzles; associated J-groove welds; and the 

adjoining upper RV closure head. The program 

includes: (1) a primary water stress corrosion 

cracking susceptibility assessment to rank the 

upper VHP nozzles according to the ranking 

criteria in the First Revised Order EA-03-009 for 

“Low,” “Moderate,” “High,” and “Replaced” 

ranking categories, (2) specific augmented 

inspection techniques and monitoring 

frequencies for performing augmented 

inspections of the upper VHP nozzles and 

upper reactor vessel heads, as defined in the 

First Revised Order EA-03-009 and based on 

the susceptible ranking category for the VHP 

nozzles, (3) specific flaw evaluation acceptance 

criteria to be used if cracking or loss of material 

is detected in the VHP nozzles or upper reactor 

vessel heads, and (4) specific corrective actions 

to be taken if the acceptance criteria for 

detected indications are exceeded.

Existing program

One-Time Inspection This program verifies the effectiveness of other 

aging management programs by determining if 

the aging effect is not occurring or the aging 

effect is progressing slowly so that the intended 

function will be maintained during the period of 

extended operation. 

Inspection should be 

completed before the 

period of extended 

operation.
NUREG-1800, Rev. 1 3.1-42 September 2005

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

One-time Inspection 

of ASME Code Class 

1 Small Bore-Piping

This program is a one-time volumetric

inspection of a sample of ASME Code Class 1 

piping less than NPS 4. 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 small-bore piping includes 

locations that are susceptible to cracking. This 

program is applicable only to plants that have 

not experienced cracking of ASME Code Class 

1 small-bore piping resulting from stress 

corrosion or thermal fatigue. Should evidence of 

significant aging be revealed by a one-time 

inspection or previous operating experience, 

periodic inspection will be proposed, as 

managed by a plant-specific program.

The inspection 

should be completed 

before the period of 

extended operation

Plant-specific AMP The description should contain information 

associated with the basis for determining that 

aging effects will be managed during the period 

of extended operation.

Program should be 

implemented before 

the period of 

extended operation.

Reactor Head 

Closure Studs

This program includes inservice inspection ISI. 

For boiling water reactors (BWRs), this program 

also includes additional preventive actions and 

inspection techniques.

Existing program

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 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. 

The surveillance 

capsule withdrawal 

schedule should be 

revised before the 

period of extended 

operation.
September 2005 3.1-43 NUREG-1800, Rev. 1

Table 3.1-2 FSAR Supplement for Aging Management of Reactor Vessel, 

Internals, and Reactor Coolant System

Program Description of Program

Implementation 

Schedule*

Selective Leaching of 

Materials

The program includes a hardness measurement 

of selected components that may be 

susceptible to selective leaching 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. For 

systems subjected to environments where 

water is not treated (i.e., the open-cycle cooling 

water system and the ultimate heat sinks), the 

program also follows the guidance in NRC GL 

89-13.

Program should be 

implemented before 

the period of 

extended operation.

Steam Generator 

Tube Integrity

This program consists of SG inspection scope, 

frequency, acceptance criteria for the plugging 

and repair of flawed tubes in accordance with 

the plant technical specifications and includes 

commitments to NEI 97-06. 

Existing program

Thermal Aging and 

Neutron Irradiation 

Embrittlement of 

Cast Austenitic 

Stainless Steel

(CASS)

The program consists of (1) determination of 

the susceptibility of cast austenitic stainless 

steel components to thermal aging 

embrittlement, (2) accounting for the synergistic 

effects of thermal aging and neutron irradiation, 

and (3) implementing a supplemental 

examination program, as necessary.

Program should be 

implemented before 

the period of 

extended operation.

Thermal Aging of 

Cast Austenitic 

Stainless Steel

(CASS)

This program includes (a) determination of the 

susceptibility of cast austenitic stainless steel 

components to thermal aging embrittlement and 

(b) for potentially susceptible components aging 

management is accomplished through either 

enhanced volumetric examination or plant- or 

component-specific flaw tolerance evaluation. 

Existing program

Water Chemistry To mitigate aging effects on component 

surfaces that are exposed to water as process 

fluid, 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 EPRI guidelines.

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.
NUREG-1800, Rev. 1 3.1-44 September 2005

This Page Intentionally Left Blank
September 2005 3.2-1 NUREG-1800, Rev. 1

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

• AMRs 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. 1 3.2-2 September 2005

The applicant’s LRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific LRA AMR line-item and the associated LRA AMP are consistent with 

the cited GALL Report AMR line-item. The reviewer should then confirm that the LRA AMR lineitem is consistent with the GALL Report AMR line-item to which it is compared.

For AMPs, 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 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.

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 apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.

3.2.2.2.1 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 

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 for internal surfaces of 

stainless steel containment isolation piping, piping components, and piping elements

exposed to treated water. The existing AMP relies on monitoring and control of water 

chemistry to mitigate degradation. However, control of water chemistry does not preclude 
September 2005 3.2-3 NUREG-1800, Rev. 1

loss of material due to pitting and crevice corrosion at locations of stagnant flow conditions. 

Therefore, the effectiveness of the chemistry control program should be verified to ensure 

that corrosion is not occurring. The GALL Report recommends further evaluation of 

programs to verify the effectiveness of the chemistry control program. A one-time inspection 

of select components at susceptible locations is an acceptable method to determine whether 

an aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

2. Loss of material from pitting and crevice corrosion could occur for stainless steel piping, 

piping components, and piping elements exposed to soil. 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. Loss of material from pitting and crevice corrosion could occur for BWR stainless steel and 

aluminum piping, piping components, and piping elements exposed to treated water. The 

existing AMP relies on monitoring and control of water chemistry for BWRs to mitigate 

degradation. 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 chemistry control program should be verified to ensure that corrosion is 

not occurring. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of the water chemistry control program. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

4. Loss of material from pitting and crevice corrosion could occur for stainless steel and copper 

alloy piping, piping components, and piping elements exposed to lubricating oil. The existing 

program relies on the periodic sampling and analysis of lubricating oil to maintain 

contaminants within acceptable limits, thereby preserving an environment that is not 

conducive to corrosion. However, control of lube oil contaminants may not always have 

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil control 

should be verified to ensure that corrosion is not occurring. The GALL Report recommends 

further evaluation to verify the effectiveness of the lubricating oil program. A one-time 

inspection of selected components at susceptible locations is an acceptable method to 

ensure that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. 

5. Loss of material from pitting and crevice corrosion could occur for of 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).

6. Loss of material from pitting and crevice corrosion could occur for stainless steel piping, 

piping components, piping elements, and tanks exposed to internal condensation. 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).
NUREG-1800, Rev. 1 3.2-4 September 2005

3.2.2.2.4 Reduction of Heat Transfer due to Fouling

1. Reduction of heat transfer due to fouling could occur for steel, stainless steel, and copper 

alloy heat exchanger tubes exposed to lubricating oil. The existing AMP relies on monitoring 

and control of lube oil chemistry to mitigate reduction of heat transfer due to fouling. 

However, control of lube oil chemistry may not always have been adequate to preclude 

fouling. Therefore, the effectiveness of lube oil chemistry control should be verified to ensure 

that fouling is not occurring. The GALL Report recommends further evaluation of programs 

to verify the effectiveness of lube oil chemistry control. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

2. Reduction of heat transfer due to fouling could occur for stainless steel heat exchanger 

tubes exposed to treated water. The existing program relies on control of water chemistry to 

manage reduction of heat transfer due to fouling. However, control of water chemistry may 

have been inadequate. Therefore, the GALL report recommends that the effectiveness of 

the chemistry control program should be verified to ensure that reduction of heat transfer 

due to fouling is not occurring. A one-time inspection is an acceptable method to ensure that 

reduction of heat transfer is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

3.2.2.2.5 Hardening and Loss of Strength due to Elastomer Degradation

Hardening and loss of strength due to elastomer degradation could occur in elastomer seals 

and components associated with the BWR Standby Gas Treatment System ductwork and filters

exposed to air-indoor uncontrolled. The GALL Report recommends further evaluation of a plantspecific 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 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).

3.2.2.2.7 Loss of Material due to General Corrosion and Fouling 

Loss of material due to general corrosion and fouling 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 
September 2005 3.2-5 NUREG-1800, Rev. 1

managed. Acceptance criteria are described in Branch Technical Position RSLB-1 (Appendix 

A.1 of this SRP-LR).

3.2.2.2.8 Loss of material due to General, Pitting, and Crevice Corrosion

1. Loss of material due to general, pitting and crevice corrosion could occur for BWR steel 

piping, piping components, and piping elements exposed to treated water. The existing AMP

relies on monitoring and control of water chemistry) for BWRs to mitigate degradation. 

However, control of water chemistry does not preclude loss of material due to general, 

pitting, and crevice corrosion at locations of stagnant flow conditions. Therefore, the 

effectiveness of the chemistry control program should be verified to ensure that corrosion is 

not occurring. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of the water chemistry control program. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

2. Loss of material due to general, pitting and crevice corrosion could occur for the internal 

surfaces of steel containment isolation piping, piping components, and piping elements 

exposed to treated water. The existing AMP relies on monitoring and control of water 

chemistry to mitigate degradation. However, control of water chemistry does not preclude 

loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow 

conditions. Therefore, the effectiveness of the water chemistry control program should be 

verified to ensure that corrosion is not occurring. The GALL Report recommends further 

evaluation of programs to verify the effectiveness of the chemistry control program. A onetime inspection of select components at susceptible locations is an acceptable method to 

determine whether an aging effect is not occurring or an aging effect is progressing very 

slowly such that the component’s intended function will be maintained during the period of 

extended operation.

3. Loss of material due to general, pitting and crevice corrosion could occur for steel piping, 

piping components, and piping elements exposed to lubricating oil. The existing program 

relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

However, control of lube oil contaminants may not always have been adequate to preclude 

corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure 

that corrosion is not occurring. The GALL Report recommends further evaluation to verify 

the effectiveness of the lubricating oil program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

3.2.2.2.9 Loss of material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion (MIC)

Loss of material due to general, pitting, crevice, and MIC could occur for steel (with or without 

coating or wrapping) piping, piping components, and piping elements buried in soil. The buried 

piping and tanks inspection program relies on industry practice, frequency of pipe excavation, 

and operating experience to manage the effects of loss of material from general, pitting, and 

crevice corrosion and MIC. The effectiveness of the buried piping and tanks inspection program 

should be verified to evaluate an applicant's inspection frequency and operating experience with 
NUREG-1800, Rev. 1 3.2-6 September 2005

buried components, ensuring that loss of material is not occurring.

3.2.2.2.10 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 GALL Report

Acceptance criteria are described in Branch Technical Position RSLB-1 (Appendix A.1 of this 

SRP-LR).

3.2.2.4 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. Examples of the type of information to be included are provided in 

Table 3.2-2 of this SRP-LR.

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.

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 
September 2005 3.2-7 NUREG-1800, Rev. 1

of the GALL Report AMP with which the applicant is claiming to be consistent, 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. In this table, the ID column provides a row identifier useful in matching the 

information presented in the corresponding table in the GALL Report, Vol. 1. The Related Item 

column identifies the item number in the GALL Report, Vol. 2, Chapters II through VIII, 

presenting detailed information summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL Report AMR line-item to which the LRA AMR 

line-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.

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 the internal surfaces of stainless steel 

containment isolation piping, piping components, and piping elements exposed to treated 

water to verify the effectiveness of the chemistry control program. A one-time inspection of 

select components at susceptible locations is an acceptable method to determine whether 

an aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 
NUREG-1800, Rev. 1 3.2-8 September 2005

based on severity of conditions, time of service, and lowest design margin. The inspection 

techniques may include visual, ultrasonic, and surface examination techniques. Follow-up 

actions are to be based on the inspection results.

2. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for stainless steel components exposed to soil, 

raw water, or internal condensation. 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.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for stainless steel and aluminum piping, piping 

components, and piping elements exposed to treated water to verify the effectiveness of the 

chemistry control program. A one-time inspection of select components at susceptible 

locations is an acceptable method to determine whether an aging effect is not occurring or 

an aging effect is progressing very slowly such that the component’s intended function will 

be maintained during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques.

Follow-up actions are to be based on the inspection results.

4. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of stainless steel and copper alloy piping, piping 

components, and piping elements exposed to lubricating oil. The existing program relies on 

monitoring and control of lubricating oil contamination to maintain contaminants within 

acceptable limits. The effectiveness of lubricating oil control should be verified to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques. 

Follow-up actions are to be based on the inspection results.
September 2005 3.2-9 NUREG-1800, Rev. 1

3.2.3.2.4 Reduction of Heat Transfer due to Fouling

1. The GALL Report recommends further evaluation of programs to manage reduction of heat 

transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger tubes 

exposed to lubricating oil to verify the effectiveness of lube oil chemistry control. A one-time 

inspection of select components at susceptible locations is an acceptable method to 

determine whether an aging effect is not occurring or an aging effect is progressing very 

slowly such that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to determine whether fouling is not 

occurring or is progressing very slowly so that the component’s intended function will be 

maintained during the period of extended operation. If an applicant proposes a one-time 

inspection of select components at susceptible locations to ensure that fouling is not 

occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques.

Follow-up actions are to be based on the inspection results.

2. The GALL report recommends further evaluation of programs to verify the effectiveness of 

control of water chemistry to manage reduction of heat transfer due to fouling for stainless 

steel heat exchanger tubes exposed to treated water on either side. 

The reviewer reviews the applicant’s proposed program to ensure that fouling is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the 

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques. Follow-up actions are to be based on the 

inspection results.

3.2.3.2.5 Hardening and Loss of Strength due to Elastomer Degradation

The GALL Report recommends further evaluation of programs to manage changes in properties 

due to degradation of elastomer seals and components associated with BWR standby gas 

treatment system ductwork and filters. 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 

changes in properties due to degradation of elastomer seals and components in the standby 

gas treatment system.

3.2.3.2.6 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.
NUREG-1800, Rev. 1 3.2-10 September 2005

3.2.3.2.7 Loss of Material due to General Corrosion and Fouling 

The GALL Report recommends further evaluation of programs to manage loss of material due 

to general corrosion and fouling 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.

3.2.3.2.8 Loss of Material due to General, Pitting, and Crevice Corrosion

1. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, and crevice corrosion for BWR steel piping, piping components, and 

piping elements exposed to treated water to verify the effectiveness of the chemistry control 

program. A one-time inspection of select components at susceptible locations is an 

acceptable method to determine whether an aging effect is not occurring or an aging effect 

is progressing very slowly such that the component’s intended function will be maintained 

during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques.

Follow-up actions are to be based on the inspection results.

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, and crevice corrosion for the internal surfaces of steel containment 

isolation piping, piping components, and piping elements exposed to treated water to verify 

the effectiveness of the chemistry control program. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques.

Follow-up actions are to be based on the inspection results.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, and crevice corrosion of steel piping, piping components, 
September 2005 3.2-11 NUREG-1800, Rev. 1

and piping elements exposed to lubricating oil. The existing program relies on monitoring 

and control of lubricating oil contamination to maintain contaminants within acceptable limits. 

The effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The reviewer 

also verifies that the proposed inspection would be performed using techniques similar to 

ASME Code and ASTM standards, including visual, ultrasonic, and surface techniques.

Follow-up actions are to be based on the inspection results.

3.2.3.2.9 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion

The GALL Report recommends further evaluation of programs to manage loss of material due 

to general, pitting, crevice, and MIC of the external surfaces of buried steel (with or without 

coating or wrapping) piping, piping components, and piping elements to verify the effectiveness 

of the buried piping and tanks inspection program. The buried piping and tanks inspection 

program relies on industry practice, frequency of pipe excavation, and operating experience to 

manage the effects of loss of material from general, pitting, and crevice corrosion and MIC. The 

effectiveness of the buried piping and tanks inspection program should be verified to evaluate 

an applicant’s inspection frequency and operating experience with buried components, ensuring 

that corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

3.2.3.2.10 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.
NUREG-1800, Rev. 1 3.2-12 September 2005

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 

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 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in 

Table 3.2-2 in the FSAR Supplement for aging management of the engineered safety features 

for license renewal. The reviewer also confirms that the applicant has provided information 

equivalent to that in Table 3.2-2 in the FSAR Supplement for Section 3.2.3.3, “AMR Results Not 

Consistent with or Not Addressed in the GALL Report.” 

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 3.2-2, 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.

3.2.4 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).
September 2005 3.2-13 NUREG-1800, Rev. 1

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,” U.S. Nuclear Regulatory Commission, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.
NUREG-1800, Rev. 1 3.2-14 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

1 BWR/ 

PWR

Steel and stainless steel piping, 

piping components, and piping 

elements in emergency core 

cooling system 

Cumulative fatigue damage TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 3.2.2.2.1)

E-10

E-13

2 PWR Steel with stainless steel cladding 

pump casing 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 plantspecific program 

addresses cladding 

breach (See 

subsection 3.2.2.2.2)

EP-49

3 BWR/ 

PWR

Stainless steel containment 

isolation piping and components 

internal surfaces exposed to 

treated water

Loss of material due to pitting 

and crevice corrosion

Water Chemistry and OneTime InspectionYes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.3.1) 

E-33

4 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to soil

Loss of material due to pitting 

and crevice corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant-specific 

(See subsection 

3.2.2.2.3.2) 

EP-31

5 BWR Stainless steel and aluminum 

piping, piping components, and 

piping elements exposed to treated 

water

Loss of material due to pitting 

and crevice corrosion

Water Chemistry and OneTime InspectionYes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.3.3) 

EP-26

EP-32
September 2005 3.2-15 NUREG-1800, Rev. 1

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

6 BWR/ 

PWR

Stainless steel and copper alloy 

piping, piping components, and 

piping elements exposed to 

lubricating oil

Loss of material due to pitting 

and crevice corrosion

Lubricating Oil Analysis 

and One-Time Inspection

Yes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.3.4)

EP-45

EP-51

7 BWR/ 

PWR

Partially encased stainless steel 

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 bottoms because 

moisture and water can 

egress under the tank due 

to cracking of the 

perimeter seal from 

weathering.

Yes, plant-specific

(See subsection 

3.2.2.2.3.5) 

E-01

8 BWR/ 

PWR

Stainless steel piping, piping 

components, piping elements, and 

tank internal surfaces exposed to 

condensation (internal)

Loss of material due to pitting 

and crevice corrosion

A plant-specific aging 

management program is to 

be evaluated. 

Yes, plant-specific

(See subsection 

3.2.2.2.3.6) 

E-14

EP-53

9 BWR/ 

PWR

Steel, stainless steel, and copper 

alloy heat exchanger tubes 

exposed to lubricating oil

Reduction of heat transfer due 

to fouling

Lubricating Oil Analysis 

and One-Time Inspection

Yes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.4.1)

EP-40

EP-47

EP-50

10 BWR/ 

PWR

Stainless steel heat exchanger 

tubes exposed to treated water

Reduction of heat transfer due 

to fouling

Water Chemistry and OneTime InspectionYes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.4.2)

EP-34
NUREG-1800, Rev. 1 3.2-16 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

11 BWR Elastomer seals and components 

in standby gas treatment system 

exposed to air - indoor 

uncontrolled

Hardening and loss of strength 

due to elastomer degradation

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant-specific

(See subsection 

3.2.2.2.5)

E-06

12 PWR Stainless steel high-pressure 

safety injection (charging) pump 

miniflow orifice exposed to treated 

borated water

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. 

Yes, plant-specific

(See subsection 

3.2.2.2.6) 

E-24

13 BWR Steel drywell and suppression 

chamber spray system nozzle and 

flow orifice internal surfaces 

exposed to air - indoor 

uncontrolled (internal)

Loss of material due to general 

corrosion and fouling

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant-specific

(See subsection 

3.2.2.2.7)

E-04

14 BWR Steel piping, piping components, 

and piping elements exposed to 

treated water

Loss of material due to 

general, pitting, and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.8.1)

E-08

15 BWR/ 

PWR

Steel containment isolation piping, 

piping components, and piping 

elements internal surfaces 

exposed to treated water

Loss of material due to 

general, pitting, and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.8.2)

E-31

16 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

lubricating oil

Loss of material due to 

general, pitting, and crevice 

corrosion

Lubricating Oil Analysis 

and One-Time Inspection

Yes, detection of aging 

effects is to be 

evaluated (See 

subsection 3.2.2.2.8.3)

EP-46
September 2005 3.2-17 NUREG-1800, Rev. 1

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

17 BWR/ 

PWR

Steel (with or without coating or 

wrapping) piping, piping 

components, and piping elements 

buried in soil

Loss of material due to 

general, pitting, crevice, and 

microbiologically-influenced 

corrosion

Buried Piping and Tanks 

Surveillance 

or 

Buried Piping and Tanks 

Inspection

No 

Yes, detection of aging 

effects and operating 

experience are to be 

further evaluated (See 

subsection 3.2.2.2.9) 

E-42

18 BWR Stainless steel piping, piping 

components, and piping elements 

exposed to treated water >60°C 

(>140°F)

Cracking due to stress 

corrosion cracking and 

intergranular stress corrosion 

cracking

BWR Stress Corrosion 

Cracking and Water 

Chemistry

No E-37

19 BWR Steel piping, piping components, 

and piping elements exposed to 

steam or treated water

Wall thinning due to flowaccelerated corrosionFlow-Accelerated 

Corrosion 

No E-07

E-09

20 BWR Cast austenitic stainless steel 

piping, piping components, and 

piping elements exposed to treated 

water (borated or unborated) 

>250°C (>482°F)

Loss of fracture toughness due 

to thermal aging embrittlement

Thermal Aging 

Embrittlement of CASS

No E-11

21 BWR/ 

PWR

High-strength steel closure bolting 

exposed to air with steam or water 

leakage

Cracking due to cyclic loading, 

stress corrosion cracking

Bolting Integrity No E-03
NUREG-1800, Rev. 1 3.2-18 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

22 BWR/ 

PWR

Steel closure bolting exposed to air 

with steam or water leakage

Loss of material due to general 

corrosion

Bolting Integrity No E-02

23 BWR/ 

PWR

Steel bolting and closure bolting 

exposed to air – outdoor (external), 

or air – indoor uncontrolled 

(external)

Loss of material due to 

general, pitting, and crevice 

corrosion

Bolting Integrity No EP-1

EP-25

24 BWR/ 

PWR

Steel closure bolting exposed to air 

– indoor uncontrolled (external)

Loss of preload due to thermal 

effects, gasket creep, and selfloosening 

Bolting Integrity No EP-24

25 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to closed cycle cooling 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

Closed-Cycle Cooling 

Water System

No EP-44

26 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

Closed-Cycle Cooling 

Water System

No EP-48

27 BWR/ 

PWR

Steel heat exchanger components 

exposed to closed cycle cooling 

water

Loss of material due to 

general, pitting, crevice, and 

galvanic corrosion

Closed-Cycle Cooling 

Water System

No E-17
September 2005 3.2-19 NUREG-1800, Rev. 1

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

28 BWR/ 

PWR

Stainless steel piping, piping 

components, piping elements, and 

heat exchanger components 

exposed to closed-cycle cooling 

water

Loss of material due to pitting 

and crevice corrosion

Closed-Cycle Cooling 

Water System

No E-19

EP-33

29 BWR/ 

PWR

Copper alloy piping, piping 

components, piping elements, and 

heat exchanger components 

exposed to closed cycle cooling 

water

Loss of material due to pitting, 

crevice, and galvanic corrosion

Closed-Cycle Cooling 

Water System

No EP-13

EP-36

30 BWR/ 

PWR

Stainless steel and copper alloy 

heat exchanger tubes exposed to 

closed cycle cooling water

Reduction of heat transfer due 

to fouling

Closed-Cycle Cooling 

Water System

No EP-35

EP-39

31 BWR/ 

PWR

External surfaces of steel 

components including ducting, 

piping, ducting closure bolting, and 

containment isolation piping 

external surfaces exposed to air -

indoor uncontrolled (external); 

condensation (external) and air -

outdoor (external)

Loss of material due to general 

corrosion

External Surfaces 

Monitoring

No E-26

E-30

E-35

E-40

E-44

E-45

E-46

32 BWR/ 

PWR

Steel piping and ducting 

components and internal surfaces 

exposed to air – indoor 

uncontrolled (Internal)

Loss of material due to general 

corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No E-25

E-29
NUREG-1800, Rev. 1 3.2-20 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

33 BWR/ 

PWR

Steel encapsulation components 

exposed to air-indoor uncontrolled 

(internal)

Loss of material due to 

general, pitting, and crevice 

corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No EP-42

34 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

condensation (internal)

Loss of material due to 

general, pitting, and crevice 

corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No E-27

35 BWR/ 

PWR

Steel containment isolation piping 

and components internal surfaces 

exposed to raw water

Loss of material due to 

general, pitting, crevice, and 

microbiologically-influenced 

corrosion, and fouling

Open-Cycle Cooling Water 

System

No E-22

36 BWR/ 

PWR

Steel heat exchanger components 

exposed to raw water

Loss of material due to 

general, pitting, crevice, 

galvanic, and 

microbiologically-influenced 

corrosion, and fouling

Open-Cycle Cooling Water 

System

No E-18

37 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to raw water

Loss of material due to pitting, 

crevice, and microbiologicallyinfluenced corrosion

Open-Cycle Cooling Water 

System

No EP-55
September 2005 3.2-21 NUREG-1800, Rev. 1

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

38 BWR/ 

PWR

Stainless steel containment 

isolation piping and components 

internal surfaces exposed to raw 

water

Loss of material due to pitting, 

crevice, and microbiologicallyinfluenced corrosion, and 

fouling

Open-Cycle Cooling Water 

System

No E-34

39 BWR/ 

PWR

Stainless steel heat exchanger 

components exposed to raw water

Loss of material due to pitting, 

crevice, and microbiologicallyinfluenced corrosion, and 

fouling

Open-Cycle Cooling Water 

System

No E-20

40 BWR/ 

PWR

Steel and stainless steel heat 

exchanger tubes (serviced by 

open-cycle cooling water) exposed 

to raw water

Reduction of heat transfer due 

to fouling

Open-Cycle Cooling Water 

System

No E-21

E-23

41 BWR/ 

PWR

Copper alloy >15% Zn piping, 

piping components, piping 

elements, and heat exchanger 

components exposed to closed 

cycle cooling water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No EP-27

EP-37

42 BWR/ 

PWR

Gray cast iron piping, piping 

components, piping elements

exposed to closed-cycle cooling 

water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No EP-52
NUREG-1800, Rev. 1 3.2-22 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

43 BWR/ 

PWR

Gray cast iron piping, piping 

components, and piping elements 

exposed to soil

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No EP-54

44 BWR/ 

PWR

Gray cast iron motor cooler 

exposed to treated water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No E-43

45 PWR Aluminum, copper alloy >15% Zn, 

and steel external surfaces, 

bolting, and piping, piping 

components, and piping elements 

exposed to air with borated water 

leakage

Loss of material due to Boric 

acid corrosion

Boric Acid Corrosion No E-28

E-41

EP-2

EP-38

46 PWR Steel encapsulation components 

exposed to air with borated water 

leakage (internal)

Loss of material due to 

general, pitting, crevice and 

boric acid corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No EP-43

47 PWR Cast austenitic stainless steel 

piping, piping components, and 

piping elements exposed to treated 

borated water >250°C (> 482°F)

Loss of fracture toughness due 

to thermal aging embrittlement

Thermal Aging 

Embrittlement of CASS

No E-47
September 2005 3.2-23 NUREG-1800, Rev. 1

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

48 PWR Stainless steel or stainless-steelclad steel piping, piping 

components, piping elements, and 

tanks (including safety injection 

tanks/accumulators) exposed to 

treated borated water >60°C 

(>140°F)

Cracking due to stress 

corrosion cracking

Water Chemistry No E-12

E-38

49 PWR Stainless steel piping, piping 

components, piping elements, and 

tanks exposed to treated borated 

water

Loss of material due to pitting 

and crevice corrosion

Water Chemistry No EP-41

50 BWR/ 

PWR

Aluminum piping, piping 

components, and piping elements 

exposed to air- indoor uncontrolled 

(internal/external)

None None NA - No AEM or AMP EP-3

51 BWR/ 

PWR

Galvanized steel ducting exposed 

to air – indoor controlled (external)

None None NA - No AEM or AMP EP-14

52 BWR/ 

PWR

Glass piping elements exposed to 

air – indoor uncontrolled (external), 

lubricating oil, raw water, treated 

water, or treated borated water 

None None NA - No AEM or AMP EP-15

EP-16

EP-28

EP-29

EP-30
NUREG-1800, Rev. 1 3.2-24 September 2005

Table 3.2-1 Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the GALL 

Report

ID Type Component Aging Effect/Mechanism Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

53 BWR/ 

PWR

Stainless steel, copper alloy, and 

nickel alloy piping, piping 

components, and piping elements 

exposed to air – indoor 

uncontrolled (external)

None None NA - No AEM or AMP EP-10

EP-17

EP-18

54 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to air 

– indoor controlled (external)

None None NA - No AEM or AMP EP-4

55 BWR/ 

PWR

Steel and stainless steel piping, 

piping components, and piping 

elements in concrete

None None NA - No AEM or AMP EP-5

EP-20

56 BWR/ 

PWR

Steel, stainless steel, and copper 

alloy piping, piping components, 

and piping elements exposed to 

gas

None None NA - No AEM or AMP EP-7

EP-9

EP-22

57 PWR Stainless steel and copper alloy 

<15% Zn piping, piping 

components, and piping elements 

exposed to air with borated water 

leakage

None None NA - No AEM or AMP EP-12

EP-19
September 2005 3.2-25 NUREG-1800, Rev. 1

Table 3.2-2 FSAR Supplement for Aging Management of Engineered Safety Features

Program Description of Program

Implementation 

Schedule*

Bolting Integrity This program relies on recommendations for a 

comprehensive bolting integrity program, as 

delineated in NUREG-1339, and industry 

recommendations, as delineated in the Electric 

Power Research Institute (EPRI) NP-5769, with the 

exceptions noted in NUREG-1339 for safety-related 

bolting. The program relies on industry 

recommendations for a comprehensive bolting 

maintenance, as delineated in the EPRI TR-104213 

for pressure retaining bolting and structural bolting. 

The program generally includes periodic inspection 

of closure bolting for indication 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. 

Other aging management programs, such as XI.M1, 

“ASME Section XI Inservice Inspection (ISI) 

Subsections IWB, IWC, and IWD” and XI.S3, “ASME 

Section XI Subsection IWF” also manage inspection 

of safety-related bolting and supplement this bolting 

integrity program. This program covers bolting within 

the scope of license renewal, including:1) safetyrelated bolting, 2) bolting for nuclear steam supply 

system (NSSS) component supports, 3) bolting for 

other pressure retaining components, including nonsafety-related bolting, and 4) structural bolting. 

(actual measured yield strength > 150 ksi).

Existing program

Boric Acid Corrosion The program consists of (1) visual inspection of 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of leak 

path and removal of the boric acid residues, 

(3) assessment of the damage, and (4) follow up 

inspection for adequacy. This program is 

implemented in response to GL 88-05 and recent 

operating experience.

Existing program

Buried Piping And 

Tanks Inspection

The program includes (1) preventive measures to 

mitigate corrosion, and (2) periodic inspection to 

manage the effects of corrosion on the pressureretaining capacity of buried steel piping and tanks. 

Preventive measures are in accordance with 

standard industry practice for maintaining external 

coatings and wrappings and cathodic protection. As 

an alternative, buried piping and tanks are inspected 

visually for any evidence of damage when they are 

excavated during maintenance and when a pipe is 

dug up and inspected for any reason with a 

frequency that is based on operating experience.

Program should be 

implemented before 

the period of 

extended operation.
NUREG-1800, Rev. 1 3.2-26 September 2005

Table 3.2-2 FSAR Supplement for Aging Management of Engineered Safety Features

Program Description of Program

Implementation 

Schedule*

Buried Piping And 

Tanks Surveillance

The program includes preventive measures to 

mitigate corrosion by protecting the external surface 

of buried piping and components, e.g., coating, 

wrapping, and a cathodic protection system. The 

program also includes surveillance and monitoring of 

the coating conductance versus time or current. This 

program is based on standard industry practices as 

described in NACE-RP-0285-95 and RP-0169-96.

Existing program

BWR Stress

Corrosion Cracking

The program to manage intergranular stress 

corrosion cracking (IGSCC) in boiling water reactor 

coolant pressure boundary piping made of stainless 

steel (SS) is delineated, in part, in NUREG-0313, 

Rev. 2, and Nuclear Regulatory Commission (NRC) 

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

The program includes (a) preventive measures to 

mitigate IGSCC and (b) inspections to monitor 

IGSCC and its effects

Existing Program

Closed-Cycle 

Cooling Water 

System 

The program relies on preventive measures to 

minimize corrosion and SCC by maintaining 

inhibitors and by performing non-chemistry 

monitoring consisting of inspection and 

nondestructive evaluations based on the guidelines 

of EPRI-TR-107396 for closed–cycle cooling water 

systems.

Existing program

External Surfaces 

Monitoring Program

This program is based on system inspections and 

walkdowns. This program consists of periodic visual 

inspections of components such as piping, piping 

components, ducting, and other equipment within 

the scope of license renewal and subject to aging 

management review in order to manage aging 

effects. The program manages aging effects through 

visual inspection of external surfaces for evidence of 

material loss and leakage. Loss of material due to 

boric acid corrosion is managed by the Boric Acid 

Corrosion Program. Surfaces that are inaccessible 

during plant operations are inspected during 

refueling outages. Surfaces that are inaccessible 

during both plant operations and refueling outages 

are inspected at frequencies to provide reasonable 

assurance that effect of aging will be managed such 

that applicable components will perform their 

intended function during the period of extended 

operation.

Existing program

Flow-Accelerated 

Corrosion (FAC) 

The program consists of (1) conduct appropriate 

analysis and baseline inspection, (2) determine 

extent of thinning, and replace/repair components, 

and (3) perform follow-up inspections to confirm or 

quantify and take longer-term corrective actions. The 

program relies on implementation of EPRI guidelines 

of NSAC-202L-R2. 

Existing program
September 2005 3.2-27 NUREG-1800, Rev. 1

Table 3.2-2 FSAR Supplement for Aging Management of Engineered Safety Features

Program Description of Program

Implementation 

Schedule*

Inspection of Internal

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components

The program visually inspects internal surfaces of 

steel piping, piping elements, ducting, and 

components in an internal environment (indoor 

uncontrolled air, condensation, and steam) that are 

not included in other aging management programs, 

for loss of material. Inspections are performed when 

the internal surfaces are accessible during the 

performance of periodic surveillance tests, during 

preventive maintenance activities or during 

scheduled outages. The program includes visual 

inspection to assure that existing environment 

conditions are not causing material degradation that 

could result in a loss of system intended functions.

Existing program

Lubricating Oil 

Analysis

This program ensures the oil environment in the 

mechanical systems is maintained to the required 

quality. The program maintains oil systems free of 

contaminants (primarily water and particulates) 

thereby preserving an environment that is not 

conducive to loss of material, cracking, or reduction 

of heat transfer. Lubricating oil testing activities 

include sampling and analysis of lubricating oil for 

detrimental contaminants. The presence of water or 

particulates may also be indicative of inleakage and 

corrosion product buildup.

Existing program

One-Time Inspection This program verifies the effectiveness of other 

aging management program by determining if the 

aging effect is not occurring or the aging effect is 

progressing slowly so that the intended function will 

be maintained during the period of extended 

operation.

The inspection 

should be completed 

before the period of 

extended operation

Open-Cycle Cooling 

Water System 

The program includes (a) surveillance and control of 

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

inspection and maintenance program, (d) system 

walk down inspection, and (e) review of 

maintenance, operating, and training practices and 

procedures. The program provides assurance that 

the open-cycle cooling water system is in 

compliance with General Design Criteria and Quality 

Assurance to ensure that the open-cycle cooling 

water (or service water) system can be managed for 

an extended period of operation. This program is in 

response to NRC GL 89-13.

Existing program

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 before 

the period of 

extended operation
NUREG-1800, Rev. 1 3.2-28 September 2005

Table 3.2-2 FSAR Supplement for Aging Management of Engineered Safety Features

Program Description of Program

Implementation 

Schedule*

Selective Leaching of 

Materials

The program includes a hardness measurement of 

selected components that may be susceptible to 

selective leaching 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. For systems subjected to environments 

where water is not treated (i.e., the open-cycle 

cooling water system and the ultimate heat sinks), 

the program also follows the guidance in NRC GL 

89-13.

Program should be 

implemented before 

the period of 

extended operation.

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 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 componentspecific flaw tolerance evaluation.

Existing program

Water Chemistry To mitigate aging effects on component surfaces 

that are exposed to water as a process fluid, 

chemistry programs are used to control water 

impurities (e.g., chloride, fluoride, 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.

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.
September 2005 3.3-1 NUREG-1800, Rev. 1

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 non-safety 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

• AMR results not consistent with or not addressed in the GALL Report
NUREG-1800, Rev. 1 3.3-2 September 2005

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 line-item and the associated LRA AMP are consistent with 

the cited GALL Report AMR line-item. The reviewer should then confirm that the LRA AMR lineitem is consistent with the GALL Report AMR line-item to which it is compared.

For AMPs, 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 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.

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, apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.
September 2005 3.3-3 NUREG-1800, Rev. 1

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.

3.3.2.2.2 Reduction of Heat Transfer due to Fouling 

Reduction of heat transfer due to fouling could occur for stainless steel heat exchanger tubes 

exposed to treated water. The existing program relies on control of water chemistry to manage 

reduction of heat transfer due to fouling. However, control of water chemistry may have been 

inadequate. Therefore, the GALL Report recommends that the effectiveness of the water 

chemistry control program should be verified to ensure that reduction of heat transfer due to 

fouling is not occurring. A one-time inspection is an acceptable method to ensure that reduction 

of heat transfer is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

3.3.2.2.3 Cracking due to Stress Corrosion Cracking (SCC)

1. Cracking due to SCC could occur in the stainless steel piping, piping components, and 

piping elements of the BWR Standby Liquid Control system that are exposed to sodium 

pentaborate solution greater than 60°C (>140°F). The existing aging management program 

relies on monitoring and control of water chemistry to manage the aging effects of cracking 

due to SCC. However, high concentrations of impurities at crevices and locations of 

stagnant flow conditions could cause SCC. Therefore, the GALL Report recommends that 

the effectiveness of the water chemistry control program should be verified to ensure that 

SCC is not occurring. A one-time inspection of select components at susceptible locations is 

an acceptable method to ensure that SCC is not occurring and that the component’s 

intended function will be maintained during the period of extended operation.

2. Cracking due to SCC could occur in stainless steel and stainless clad steel heat exchanger 

components exposed to treated water greater than 60°C (>140°F). The GALL Report

recommends further evaluation of a plant-specific aging management program to ensure 

that these aging effects are adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3. Cracking due to SCC could occur in stainless steel diesel engine exhaust piping, piping 

components, and piping elements exposed to diesel exhaust. The GALL Report 

recommends further evaluation of a plant-specific aging management program to ensure 

that these aging effects are adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.3.2.2.4 Cracking due to Stress Corrosion Cracking and Cyclic Loading

1. Cracking due to SCC and cyclic loading could occur in stainless steel PWR nonregenerative 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 to manage the aging 

effects of cracking due to SCC. However, control of water chemistry does not preclude 

cracking due to SCC and cyclic loading. Therefore, the effectiveness of the water chemistry 
NUREG-1800, Rev. 1 3.3-4 September 2005

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.

2. Cracking due to SCC and cyclic loading could occur in stainless steel PWR regenerative 

heat exchanger components exposed to treated borated water greater than 60°C (>140°F). 

The existing aging management program relies on monitoring and control of primary water 

chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of 

water chemistry does not preclude cracking due to SCC and cyclic loading. Therefore, the 

effectiveness of 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. Acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3. Cracking due to SCC and cyclic loading could occur for the stainless steel pump casing for 

the PWR high-pressure pumps in the chemical and volume control system. The existing 

aging management program relies on monitoring and control of primary water chemistry in 

PWRs to manage the aging effects of cracking due to SCC. However, control of water 

chemistry does not preclude cracking due to SCC and cyclic loading. Therefore, the 

effectiveness of 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. Acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.3.2.2.5 Hardening and Loss of Strength due to Elastomer Degradation

1. Hardening and loss of strength due to elastomer degradation could occur in elastomer seals 

and components of heating and ventilation systems exposed to air – indoor uncontrolled 

(internal/external. The GALL Report recommends further evaluation of a plant-specific aging 

management program to ensure that these aging effects are adequately managed. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of 

this SRP-LR.) 

2. Hardening loss of strength due to elastomer degradation could occur in elastomer linings of 

the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR 

and PWR) exposed to treated water or to treated borated water. The GALL Report

recommends that a plant-specific aging management program be evaluated to determine 

and assesses the qualified life of the linings in the environment to ensure that these aging 

effects are adequately managed. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material due to General 

Corrosion

Reduction of neutron-absorbing capacity and loss of material due to general corrosion could 

occur in the neutron-absorbing sheets of BWR and PWR spent fuel storage racks exposed to 

treated water or to treated borated water. The GALL Report recommends further evaluation of a 
September 2005 3.3-5 NUREG-1800, Rev. 1

plant-specific aging management program to ensure that these aging effects are adequately 

managed. Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix 

A.1 of this SRP-LR).

3.3.2.2.7 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 piping, 

piping components, and piping elements, including the tubing, valves, and tanks in the 

reactor coolant pump oil collection system, exposed to lubricating oil (as part of the fire 

protection system). The existing aging management program relies on the periodic sampling 

and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby 

preserving an environment that is not conducive to corrosion. However, control of lube oil 

contaminants may not always have been adequate to preclude corrosion. Therefore, the 

effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring. The GALL Report recommends further evaluation of programs to manage 

corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection of 

selected components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation. 

In addition, corrosion may occur at locations in the reactor coolant pump oil collection tank 

where water from wash downs may accumulate. Therefore, the effectiveness of the program 

should be verified to ensure that corrosion is not occurring. The GALL Report recommends 

further evaluation of programs to manage loss of material due to general, pitting, and

crevice corrosion, to include determining the thickness of the lower portion of the tank. A 

one-time inspection is an acceptable method to ensure that corrosion is not occurring and 

that the component’s intended function will be maintained during the period of extended 

operation. 

2. Loss of material due to general, pitting, and crevice corrosion could occur in steel piping, 

piping components, and piping elements in the BWR reactor water cleanup and shutdown 

cooling systems exposed to treated water. The existing aging management program relies 

on monitoring and control of reactor water chemistry to manage the aging effects of loss of 

material from general, pitting and crevice corrosion. However, high concentrations of 

impurities at crevices and locations of stagnant flow conditions could cause general, pitting, 

or crevice corrosion. Therefore, the effectiveness of the chemistry control program should be 

verified to ensure that corrosion is not occurring. The GALL Report recommends further 

evaluation of programs to manage loss of material from general, pitting, and crevice 

corrosion to verify the effectiveness of the water chemistry program. A one-time inspection 

of select components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

3. Loss of material due to general (steel only) pitting and crevice corrosion could occur for steel 

and stainless steel diesel exhaust piping, piping components, and piping elements exposed 

to diesel exhaust. The GALL Report recommends further evaluation of a plant-specific aging 

management program to ensure that these aging effects are adequately managed. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of 

this SRP-LR.)
NUREG-1800, Rev. 1 3.3-6 September 2005

3.3.2.2.8 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion (MIC) 

Loss of material due to general, pitting, crevice corrosion, and microbiologically-influenced 

corrosion (MIC) could occur for steel (with or without coating or wrapping) piping, piping 

components, and piping elements buried in soil. The buried piping and tanks inspection program 

relies on industry practice, frequency of pipe excavation, and operating experience to manage 

the effects of loss of material from general, pitting, and crevice corrosion and MIC. The 

effectiveness of the buried piping and tanks inspection program should be verified to evaluate 

an applicant’s inspection frequency and operating experience with buried components, ensuring 

that loss of material is not occurring.

3.3.2.2.9 Loss of Material due to General, Pitting, Crevice,Microbiologically-Influenced

Corrosion and Fouling

1. Loss of material due to general, pitting, crevice, MIC, and fouling could occur for steel 

piping, piping components, piping elements, and tanks exposed to fuel oil. The existing 

aging management program relies on the fuel oil chemistry program for monitoring and 

control of fuel oil contamination to manage loss of material due to corrosion or fouling. 

Corrosion or fouling may occur at locations where contaminants accumulate. The 

effectiveness of the fuel oil chemistry control should be verified to ensure that corrosion is 

not occurring. The GALL Report recommends further evaluation of programs to manage 

loss of material due to general, pitting, crevice, MIC, and fouling to verify the effectiveness of 

the fuel oil chemistry program. A one-time inspection of selected components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring and that the 

component’s intended function will be maintained during the period of extended operation.

2. Loss of material due to general, pitting, crevice, MIC, and fouling could occur for steel heat 

exchanger components exposed to lubricating oil. The existing aging management program 

relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

However, control of lube oil contaminants may not always have been adequate to preclude 

corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure 

that corrosion is not occurring. The GALL Report recommends further evaluation of 

programs to manage corrosion to verify the effectiveness of the lube oil program. A one-time 

inspection of selected components at susceptible locations is an acceptable method to 

ensure that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

3.3.2.2.10 Loss of Material due to Pitting and Crevice Corrosion 

1. Loss of material due to pitting and crevice corrosion could occur in BWR and PWR steel 

piping with elastomer lining or stainless steel cladding that are exposed to treated water and 

treated borated water if the cladding or lining is degraded. The existing aging management 

program relies on monitoring and control of reactor water chemistry to manage the aging 

effects of loss of material from pitting and crevice corrosion. However, high concentrations of 

impurities at crevices and locations of stagnant flow conditions could cause pitting, or 

crevice corrosion. Therefore, the effectiveness of the chemistry control program should be 

verified to ensure that corrosion is not occurring. The GALL Report recommends further 

evaluation of programs to manage loss of material from pitting and crevice corrosion to 

verify the effectiveness of the water chemistry program. A one-time inspection of select 
September 2005 3.3-7 NUREG-1800, Rev. 1

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. 

2. Loss of material due to pitting and crevice corrosion could occur for stainless steel and 

aluminum piping, piping components, piping elements, and for stainless steel and steel with 

stainless steel cladding heat exchanger components exposed to treated water. The existing 

aging management program relies on monitoring and control of reactor water chemistry to 

manage the aging effects of loss of material from pitting and crevice corrosion. However, 

high concentrations of impurities at crevices and locations of stagnant flow conditions could 

cause pitting, or crevice corrosion. Therefore, the effectiveness of the chemistry control

program should be verified to ensure that corrosion is not occurring. The GALL Report 

recommends further evaluation of programs to manage loss of material from pitting and 

crevice corrosion to verify the effectiveness of the water chemistry program. A one-time 

inspection of select components at susceptible locations is an acceptable method to ensure 

that corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

3. Loss of material due to pitting and crevice corrosion could occur for copper alloy HVAC 

piping, piping components, and piping elements exposed to condensation (external). The 

GALL Report recommends further evaluation of a plant-specific aging management program

to ensure that these aging effects are adequately managed. Acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

4. Loss of material due to pitting and crevice corrosion could occur for copper alloy piping, 

piping components, and piping elements exposed to lubricating oil. The existing aging 

management program relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that is 

not conducive to corrosion. However, control of lube oil contaminants may not always have 

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil control 

should be verified to ensure that corrosion is not occurring. The GALL Report recommends 

further evaluation of programs to manage corrosion to verify the effectiveness of the 

lubricating oil program. A one-time inspection of selected components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring and that the 

component’s intended function will be maintained during the period of extended operation.

5. Loss of material due to pitting and crevice corrosion could occur for HVAC aluminum piping, 

piping components, and piping elements and stainless steel ducting and components 

exposed to condensation. The GALL Report recommends further evaluation of a plantspecific aging management program to ensure that these aging effects are adequately 

managed. Acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR.)

6. Loss of material due to pitting and crevice corrosion could occur for copper alloy fire 

protection system piping, piping components, and piping elements exposed to internal 

condensation. The GALL Report recommends further evaluation of a plant-specific aging 

management program to ensure that these aging effects are adequately managed. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of 

this SRP-LR.)
NUREG-1800, Rev. 1 3.3-8 September 2005

7. Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, 

piping components, and piping elements exposed to soil. The GALL Report recommends 

further evaluation of a plant-specific aging management program to ensure that these aging 

effects are adequately managed. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR.)

8. Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, 

piping components, and piping elements of the BWR Standby Liquid Control System that 

are exposed to sodium pentaborate solution. The existing aging management program 

relies on monitoring and control of water chemistry to manage the aging effects of loss of 

material due to pitting and crevice corrosion. However, high concentrations of impurities at 

crevices and locations of stagnant flow conditions could cause loss of material due to pitting 

and crevice corrosion. Therefore, the GALL Report recommends that the effectiveness of 

the water chemistry control program should be verified to ensure this aging is not occurring. 

A one-time inspection of select components at susceptible locations is an acceptable 

method to ensure that loss of material due to pitting and crevice corrosion is not occurring 

and that the component’s intended function will be maintained during the period of extended 

operation.

3.3.2.2.11 Loss of Material due to Pitting, Crevice, and Galvanic Corrosion 

Loss of material due to pitting, crevice, and galvanic corrosion could occur for copper alloy 

piping, piping components, and piping elements exposed to treated water. Therefore, the GALL 

Report recommends that the effectiveness of the water chemistry control program should be 

verified to ensure this aging is not occurring. A one-time inspection of select components at 

susceptible locations is an acceptable method to ensure that loss of material due to pitting and 

crevice corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

3.3.2.2.12 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced

Corrosion

1. Loss of material due to pitting, crevice, and MIC could occur in stainless steel, aluminum,

and copper alloy piping, piping components, and piping elements exposed to fuel oil. The 

existing aging management program relies on the fuel oil chemistry program for monitoring 

and control of fuel oil contamination to manage loss of material due to corrosion. However, 

corrosion may occur at locations where contaminants accumulate and the effectiveness of 

fuel oil chemistry control should be verified to ensure that corrosion is not occurring. The 

GALL Report recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the fuel oil chemistry control program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

2. Loss of material due to pitting, crevice, and MIC could occur in stainless steel piping, piping 

components, and piping elements exposed to lubricating oil. The existing program relies on 

the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

However, control of lube oil contaminants may not always have been adequate to preclude 

corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure 

that corrosion is not occurring. The GALL Report recommends further evaluation of 
September 2005 3.3-9 NUREG-1800, Rev. 1

programs to manage corrosion to verify the effectiveness of the lubricating oil program. A 

one-time inspection of selected components at susceptible locations is an acceptable 

method to ensure that corrosion is not occurring and that the component’s intended function 

will be maintained during the period of extended operation.

3.3.2.2.13 Loss of Material due to Wear

Loss of material due to wear could occur in the elastomer seals and components exposed to air 

indoor uncontrolled (internal or external). The GALL Report recommends further evaluation to 

ensure that these aging effects are adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.3.2.2.14 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).

3.3.2.2.15 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.)

3.3.2.3 AMR Results Not Consistent with or Not Addressed in GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this

SRP-LR.)

3.3.2.4 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. Examples of the type of information required are provided in 

Table 3.3-2 of this SRP-LR

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 
NUREG-1800, Rev. 1 3.3-10 September 2005

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. 

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 with which the applicant is claiming to be consistent, 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 GALL 

Report pertinent to the auxiliary systems components are summarized in Table 3.3-1 of this 

SRP-LR. In this table, the ID column provides a row identifier useful in matching the information 

presented in the corresponding table in the GALL Report, Vol. 1. The Related Item column 

identifies the item number in the GALL Report, Vol. 2, Chapters II through VIII, presenting 

detailed information summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL Report AMR line-item to which the LRA AMR 

line-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. 

3.3.3.2.1 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 Reduction of Heat Transfer due to Fouling

The GALL Report recommends further evaluation of programs to verify the effectiveness of 

control of water chemistry to manage reduction of heat transfer due to fouling for stainless steel 

heat exchanger tubes exposed to treated water on either side. 
September 2005 3.3-11 NUREG-1800, Rev. 1

The reviewer reviews the applicant’s proposed program to ensure that fouling not occurring and 

that the component’s intended function will be maintained during the period of extended 

operation. If the applicant proposes a one-time inspection of select components at susceptible 

locations to ensure that corrosion is not occurring, the reviewer verifies that the applicant’s 

selection of susceptible locations is based on severity of conditions, time of service, and lowest 

design margin. The reviewer also verifies that the proposed inspection would be performed 

using techniques similar to ASME Code and ASTM standards, including visual, ultrasonic, and 

surface techniques.

3.3.3.2.3 Cracking due to Stress Corrosion Cracking

1. The GALL Report recommends further evaluation of programs to manage cracking due to 

SCC of the stainless steel piping, piping components, and piping elements of the BWR 

Standby Liquid Control system that are exposed to sodium pentaborate solution greater 

than 60°C (>140°F). The water chemistry program relies on monitoring and control of 

reactor water chemistry to manage the effects of cracking from SCC. The effectiveness of

the water chemistry control program should be reviewed to verify that cracking is not 

occurring and that the component’s intended function would be maintained during the period 

of extended operation. 

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the 

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques.

2. The GALL Report recommends further evaluation of programs to manage the cracking due 

to SCC of stainless steel and stainless steel clad heat exchanger components exposed to 

treated water greater than 60°C (>140°F). 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. The GALL Report recommends further evaluation of programs to manage cracking due to 

SCC of stainless steel diesel engine exhaust piping, piping components, and piping 

elements exposed to diesel exhaust. 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.

3.3.3.2.4 Cracking due to Stress Corrosion Cracking and Cyclic Loading

1. 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 greater than

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 
NUREG-1800, Rev. 1 3.3-12 September 2005

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.

2. The GALL Report recommends further evaluation of programs to manage cracking due to 

SCC and cyclic loading in the stainless steel PWR regenerative heat exchanger 

components exposed to treated borated water greater than 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. 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. The GALL Report recommends further evaluation of programs to manage cracking due to 

cyclic loading for the stainless steel pump casing of high-pressure pumps in the PWR 

chemical and volume control system. The GALL Report recommends further evaluation to 

ensure that these aging effects are 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 these aging effects.

3.3.3.2.5 Hardening and Cracking or Loss of Strength due to Elastomer Degradation

1. The GALL Report recommends further evaluation of programs to manage the Hardening 

and loss of strength due to elastomer degradation could occur in elastomer seals and 

components of heating and ventilation systems exposed to air – indoor uncontrolled 

(internal/external. The reviewer reviews the applicant’s proposed program on a case-bycase basis to ensure that an adequate program will be in place for the management of these 

aging effects.

2. The GALL Report also recommends further evaluation of programs to manage the 

hardening and cracking due to elastomer degradation of valves in spent fuel pool cooling 

and cleanup system (BWR and PWR). 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.

3.3.3.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material due to General 

Corrosion 

The GALL Report recommends further evaluation of programs to manage reduction of neutronabsorbing capacity and loss of material due to general corrosion of the neutron-absorbing 

sheets in BWR and PWR spent fuel storage racks. 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.

3.3.3.2.7 Loss of Material due to General, Pitting, and Crevice Corrosion 

1. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, and crevice corrosion of steel piping, piping components, 

and piping elements exposed to lubricating oil, including the tanks, valve bodies, and tubing 

in the reactor coolant pump oil collection system (as part of the fire protection system). The 
September 2005 3.3-13 NUREG-1800, Rev. 1

existing program relies on monitoring and control of lubricating oil contamination to maintain 

contaminants within acceptable limits. The effectiveness of lubricating oil control should be 

verified to ensure that corrosion is not occurring and that the component’s intended function 

will be maintained during the period of extended operation.

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. If the 

applicant proposes a one-time visual inspection of the bottom portion of the interior of the 

tank, the inspection would be performed to ensure that corrosion is not occurring. If 

corrosion is identified, a volumetric examination would then be conducted on any 

problematic areas. The results of examinations will be used as a leading indicator of other 

susceptible components. The reviewer also verifies that the proposed inspection would be 

performed using techniques similar to ASME Code and ASTM standards, including visual, 

ultrasonic, and surface examination techniques.

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, and crevice corrosion of steel piping, piping component, and piping 

elements exposed to treated water in the BWR reactor water cleanup and shutdown cooling 

systems The GALL Report recommends further evaluations to verify the effectiveness of the 

water chemistry program. The water chemistry program relies on monitoring and control of 

reactor water chemistry to manage the aging effects of loss of material from general, pitting 

and crevice corrosion (Ref. 3). However, high concentrations of impurities at crevices and 

locations of stagnant flow conditions could cause general, pitting and crevice corrosion. 

Therefore, the effectiveness of the water chemistry control program should be verified to 

ensure that corrosion is not occurring and that the component’s intended function would be 

maintained during the period of extended operation. 

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the 

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques. 

3. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting and crevice corrosion in stainless steel diesel exhaust piping, piping 

components, and piping elements exposed to diesel exhaust. 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.

3.3.3.2.8 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion

The GALL Report recommends further evaluation of programs to manage loss of material due 

to general, pitting, and crevice corrosion and MIC of steel (with or without coating or wrapping) 

piping, piping components, and piping elements buried in soil. The buried piping and tanks 

inspection program relies on industry practice, frequency of pipe excavation, and operating 

experience to manage the effects of loss of material from general, pitting, and crevice corrosion 

and MIC. The effectiveness of the buried piping and tanks inspection program should be verified 
NUREG-1800, Rev. 1 3.3-14 September 2005

to evaluate an applicant’s inspection frequency and operating experience with buried 

components, ensuring that corrosion is not occurring and that the component’s intended 

function will be maintained during the period of extended operation.

3.3.3.2.9 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion and Fouling)

1. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, and crevice corrosion and MIC and to fouling of steel piping, piping 

components, piping elements, and tanks exposed to fuel oil. The fuel oil chemistry program 

relies on monitoring and control of fuel oil contamination to manage loss of material due to 

corrosion or fouling. Corrosion or fouling may occur at locations where contaminants 

accumulate. The effectiveness of the fuel oil program should be verified to ensure that 

corrosion/fouling is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

The reviewer reviews the applicant’s proposed program to ensure that corrosion/fouling is 

not occurring and that the component’s intended function will be maintained during the 

period of extended operation. If an applicant proposes a one-time inspection of select 

components and susceptible locations to ensure that corrosion/fouling is not occurring, the 

reviewer verifies that the applicant’s selection of susceptible locations is based on severity 

of conditions, time of service, and lowest design margin. The reviewer also verifies that the 

proposed inspection would be performed using techniques similar to ASME Code and 

ASTM standards, including visual, ultrasonic, and surface techniques.

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, and crevice corrosion and MIC and to fouling of steel heat exchanger 

components exposed to lubricating oil. The existing program relies on monitoring and 

control of lubricating oil contamination to maintain contaminants within acceptable limits. 

The effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The inspection 

techniques may include visual, ultrasonic, and surface examination techniques. Follow-up 

actions are to be based on the inspection results.

3.3.3.2.10 Loss of Material due to Pitting and Crevice Corrosion 

1. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting and crevice corrosion of the steel piping, piping components and piping 

elements with degraded elastomer lining or stainless steel cladding that are exposed to 

treated water or treated borated water to verify the effectiveness of the water chemistry 

program. The water chemistry program relies on monitoring and control of reactor water 

chemistry to manage the aging effects of loss of material from pitting and crevice corrosion 

(Ref. 3, 4). However, high concentrations of impurities at crevices and locations of stagnant 
September 2005 3.3-15 NUREG-1800, Rev. 1

flow conditions could cause pitting and crevice corrosion. Therefore, the effectiveness of the 

water chemistry control program should be verified to ensure that corrosion is not occurring 

and that the component’s intended function would be maintained during the period of 

extended operation. 

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the 

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques.

2. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of stainless steel and aluminum piping, piping 

components, piping elements exposed to treated water and for stainless steel and steel with 

stainless steel cladding heat exchanger components exposed to treated water. The water 

chemistry program relies on monitoring and control of reactor water chemistry to manage 

the aging effects of loss of material from pitting and crevice corrosion (Ref. 3, 4). However, 

high concentrations of impurities at crevices and locations of stagnant flow conditions could 

cause pitting and crevice corrosion. Therefore, the effectiveness of the water chemistry 

control program should be verified to ensure that corrosion is not occurring and that the 

component’s intended function would be maintained during the period of extended 

operation. 

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for copper alloy HVAC piping, piping 

components, and piping elements exposed to condensation (external). 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.

4. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of copper alloy piping, piping components, and 

piping elements exposed to lubricating oil. The existing program relies on monitoring and 

control of lubricating oil contamination to maintain contaminants within acceptable limits. 

The effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to determine whether corrosion is 

not occurring or the corrosion is progressing very slowly so that the component’s intended 
NUREG-1800, Rev. 1 3.3-16 September 2005

function will be maintained during the period of extended operation. If an applicant proposes 

a one-time inspection of select components at susceptible locations to ensure that corrosion 

is not occurring, the reviewer verifies that the applicant’s selection of susceptible locations is 

based on severity of conditions, time of service, and lowest design margin. The inspection 

techniques may include visual, ultrasonic, and surface examination techniques. Follow-up 

actions are to be based on the inspection results.

5. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of HVAC system aluminum piping, piping 

components, and piping elements and stainless steel ducting and components exposed to 

condensation. 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.

6. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of copper alloy fire protection system piping, 

piping components, and piping elements exposed to internal condensation. 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.

7. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of stainless steel piping, piping components, 

and piping elements exposed to soil. 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.

8. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion of stainless steel piping, piping components, 

and piping elements of the BWR Standby Liquid Control system that are exposed to sodium 

pentaborate solution to verify the effectiveness of the water chemistry program. The water 

chemistry program relies on monitoring and control of reactor water chemistry to manage 

the aging effects of loss of material from pitting and crevice corrosion. However, high 

concentrations of impurities at crevices and locations of stagnant flow conditions could 

cause pitting and crevice corrosion. Therefore, the effectiveness of the water chemistry 

control program should be verified to ensure that corrosion is not occurring and that the 

components’ intended function would be maintained during the period of extended 

operation. 

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If the applicant proposes a one-time inspection of select components at 

susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that the 

applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques. 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.
September 2005 3.3-17 NUREG-1800, Rev. 1

3.3.3.2.11 Loss of Material due to Pitting, Crevice, and Galvanic Corrosion 

The GALL Report recommends further evaluation of programs to manage the loss of material 

due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, and 

piping elements that are exposed to treated water. The 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.

3.3.3.2.12 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced

Corrosion

1. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting, crevice, and MIC of stainless steel, aluminum, and copper alloy piping, piping 

components, and piping elements exposed to fuel oil. The fuel oil chemistry program relies 

on monitoring and control of fuel oil contamination to manage loss of material due to 

corrosion. Corrosion may occur at locations where contaminants accumulate. The 

effectiveness of fuel oil chemistry control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If an applicant proposes a one-time inspection of select components 

and susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that 

the applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques.

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting, crevice, and MIC of stainless steel piping, piping components, and piping 

elements exposed to lubricating oil. The existing program relies on monitoring and control of 

lubricating oil contamination to maintain contaminants within acceptable limits. The 

effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the applicant’s proposed program to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. If an applicant proposes a one-time inspection of select components 

and susceptible locations to ensure that corrosion is not occurring, the reviewer verifies that 

the applicant’s selection of susceptible locations is based on severity of conditions, time of 

service, and lowest design margin. The reviewer also verifies that the proposed inspection 

would be performed using techniques similar to ASME Code and ASTM standards, including 

visual, ultrasonic, and surface techniques.

3.3.3.2.13 Loss of Material due to Wear

The GALL Report recommends further evaluation of programs to manage the loss of material 

due to wear of the elastomer seals and components of the ventilation systems. The reviewer 
NUREG-1800, Rev. 1 3.3-18 September 2005

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.

3.3.3.2.14 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. 

3.3.3.2.15 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 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).

3.3.3.4 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in 

Table 3.3-2 in the FSAR Supplement for aging management of the auxiliary systems for license 

renewal. The reviewer also confirms that the applicant has provided information equivalent to 

that in Table 3.3-2 in the FSAR Supplement for Subsection 3.3.3.3, “AMR Results Not 

Consistent with or Not Addressed in the GALL Report.” 

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.
September 2005 3.3-19 NUREG-1800, Rev. 1

As noted in Table 3.3-2, 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).

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, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.

3. ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 1989 or later edition as approved in 10 CFR 

50.55a, The American Society of Mechanical Engineers, New York, NY.

4. 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, 1983.
NUREG-1800, Rev. 1 3.3-20 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

1 BWR/ 

PWR

Steel cranes - structural girders 

exposed to air – indoor 

uncontrolled (external)

Cumulative fatigue 

damage

TLAA to be evaluated for 

structural girders of cranes. 

See the Standard Review 

Plan, Section 4.7 for generic 

guidance for meeting the 

requirements of 10 CFR 

54.21(c)(1).

Yes, TLAA (See 

subsection 3.3.2.2.1)

A-06

2 BWR/ 

PWR

Steel and stainless steel piping, 

piping components, piping 

elements, and heat exchanger 

components exposed to air –

indoor uncontrolled, treated 

borated water or treated water

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 CFR 

54.21(c)

Yes, TLAA (See 

subsection 3.3.2.2.1)

A-34

A-57

A-62

A-100

3 BWR/ 

PWR

Stainless steel heat exchanger 

tubes exposed to treated water

Reduction of heat transfer 

due to fouling

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

section 3.3.2.2.2)

AP-62

4 BWR Stainless steel piping, piping 

components, and piping 

elements exposed to sodium 

pentaborate solution >60°C 

(>140°F)

Cracking due to stress 

corrosion cracking

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.3.1)

A-59

5 BWR/ 

PWR

Stainless steel and stainless 

clad steel heat exchanger 

components exposed to treated 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.3.2)

A-71

A-85

6 BWR/ 

PWR

Stainless steel diesel engine 

exhaust piping, piping 

components, and piping 

elements exposed to diesel 

exhaust

Cracking due to stress 

corrosion cracking

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.3.3)

AP-33
September 2005 3.3-21 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

7 PWR Stainless steel non-regenerative 

heat exchanger components 

exposed to treated borated 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking and 

cyclic loading

Water Chemistry and a plantspecific verification program. 

An acceptable verification 

program is to include 

temperature and radioactivity 

monitoring of the shell side 

water, and eddy current 

testing of tubes.

Yes, plant specific 

(See subsection 

3.3.2.2.4.1)

A-69

8 PWR Stainless steel regenerative heat 

exchanger components exposed 

to treated borated water >60°C 

(>140°F)

Cracking due to stress 

corrosion cracking and 

cyclic loading

Water Chemistry and a plantspecific verification program. 

The AMP is to be augmented 

by verifying the absence of 

cracking due to stress 

corrosion cracking and cyclic 

loading. A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.4.2)

A-84

9 PWR Stainless steel high-pressure 

pump casing in PWR chemical 

and volume control system 

Cracking due to stress 

corrosion cracking and 

cyclic loading

Water Chemistry and a plantspecific verification program. 

The AMP is to be augmented 

by verifying the absence of 

cracking due to stress 

corrosion cracking and cyclic 

loading. A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.4.3)

A-76

10 BWR/ 

PWR

High-strength steel closure 

bolting exposed to air with steam 

or water leakage.

Cracking due to stress 

corrosion cracking, cyclic 

loading

Bolting Integrity

The AMP is to be augmented 

by appropriate inspection to 

detect cracking if the bolts are 

not otherwise replaced during 

maintenance.

Yes, if the bolts are 

not replaced during 

maintenance (see 

Subsection 

3.3.2.2.4.4)

A-104
NUREG-1800, Rev. 1 3.3-22 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

11 BWR/ 

PWR

Elastomer seals and 

components exposed to air –

indoor uncontrolled 

(internal/external) 

Hardening and loss of 

strength due to elastomer 

degradation

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.5.1) 

A-17

12 BWR/ 

PWR

Elastomer lining exposed to 

treated water or treated borated 

water

Hardening and loss of 

strength due to elastomer 

degradation

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.5.2) 

A-15

A-16

13 BWR/ 

PWR

Boral, boron steel spent fuel 

storage racks neutron-absorbing 

sheets exposed to treated water 

or treated borated water

Reduction of neutronabsorbing capacity and 

loss of material due to 

general corrosion

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.6) 

A-88

A-89

14 BWR/ 

PWR

Steel piping, piping component, 

and piping elements exposed to 

lubricating oil

Loss of material due to 

general, pitting, and 

crevice corrosion

Lubricating Oil Analysis and 

One-Time Inspection

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.7.1)

AP-30

15 BWR/ 

PWR

Steel reactor coolant pump oil 

collection system piping, tubing, 

and valve bodies exposed to 

lubricating oil

Loss of material due to 

general, pitting, and 

crevice corrosion

Lubricating Oil Analysis and 

One-Time Inspection

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.7.1)

A-83

16 BWR/ 

PWR

Steel reactor coolant pump oil 

collection system tank exposed 

to lubricating oil

Loss of material due to 

general, pitting, and 

crevice corrosion

Lubricating Oil Analysis and 

One-Time Inspection to 

evaluate the thickness of the 

lower portion of the tank

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.7.1)

A-82

17 BWR Steel piping, piping components, 

and piping elements exposed to 

treated water

Loss of material due to 

general, pitting, and 

crevice corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.7.2) 

A-35
September 2005 3.3-23 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

18 BWR/ 

PWR

Stainless steel and steel diesel 

engine exhaust piping, piping 

components, and piping 

elements exposed to diesel 

exhaust

Loss of material/ general 

(steel only), pitting and 

crevice corrosion

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.7.3) 

A-27

19 BWR/ 

PWR

Steel (with or without coating or 

wrapping) piping, piping 

components, and piping 

elements exposed to soil

Loss of material due to 

general, pitting, crevice, 

and microbiologically 

influenced corrosion

Buried Piping and Tanks 

Surveillance 

or 

Buried Piping and Tanks 

Inspection

No 

Yes, detection of 

aging effects and 

operating 

experience are to be 

further evaluated 

(See subsection 

3.3.2.2.8)

A-01

20 BWR/ 

PWR

Steel piping, piping components, 

piping elements, and tanks 

exposed to fuel oil

Loss of material due to 

general, pitting, crevice, 

and microbiologically 

influenced corrosion, and 

fouling

Fuel Oil Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.9.1)

A-30

21 BWR/ 

PWR

Steel heat exchanger 

components exposed to 

lubricating oil

Loss of material due to 

general, pitting, crevice, 

and microbiologically 

influenced corrosion, and 

fouling

Lubricating Oil Analysis and 

One-Time Inspection

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.9.2)

AP-39

22 BWR/ 

PWR

Steel with elastomer lining or 

stainless steel cladding piping, 

piping components, and piping 

elements exposed to treated 

water and treated borated water

Loss of material due to 

pitting and crevice

corrosion (only for steel 

after lining/cladding 

degradation)

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.10.1) 

A-39

A-40
NUREG-1800, Rev. 1 3.3-24 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

23 BWR Stainless steel and steel with 

stainless steel cladding heat 

exchanger components exposed 

to treated water

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.10.2) 

A-70

24 BWR/ 

PWR

Stainless steel and aluminum 

piping, piping components, and 

piping elements exposed to 

treated water

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.10.2) 

A-58

AP-38

25 BWR/ 

PWR

Copper alloy HVAC piping, 

piping components, piping 

elements exposed to 

condensation (external)

Loss of material due to 

pitting and crevice 

corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.10.3) 

A-46

26 BWR/ 

PWR

Copper alloy piping, piping 

components, and piping 

elements exposed to lubricating 

oil

Loss of material due to 

pitting and crevice 

corrosion

Lubricating Oil Analysis and 

One-Time Inspection

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.10.4) 

AP-47

27 BWR/ 

PWR

Stainless steel HVAC ducting 

and aluminum HVAC piping, 

piping components and piping 

elements exposed to 

condensation

Loss of material due to 

pitting and crevice 

corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.10.5) 

A-09

AP-74

28 BWR/ 

PWR

Copper alloy fire protection 

piping, piping components, and 

piping elements exposed to 

condensation (internal)

Loss of material due to 

pitting and crevice 

corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.10.6) 

AP-78

29 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping 

elements exposed to soil

Loss of material due to 

pitting and crevice 

corrosion

A plant-specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.10.7) 

AP-56
September 2005 3.3-25 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

30 BWR Stainless steel piping, piping 

components, and piping 

elements exposed to sodium 

pentaborate solution

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.10.8) 

AP-73

31 BWR Copper alloy piping, piping 

components, and piping 

elements exposed to treated 

water

Loss of material due to 

pitting, crevice, and 

galvanic corrosion

Water Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.11) 

AP-64

32 BWR/ 

PWR

Stainless steel, aluminum and 

copper alloy piping, piping 

components, and piping 

elements exposed to fuel oil

Loss of material due to 

pitting, crevice, and 

microbiologically 

influenced corrosion

Fuel Oil Chemistry and OneTime InspectionYes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.12.1)

AP-35

AP-44

AP-54

33 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping 

elements exposed to lubricating 

oil

Loss of material due to 

pitting, crevice, and 

microbiologically 

influenced corrosion

Lubricating Oil Analysis and 

One-Time Inspection

Yes, detection of 

aging effects is to be 

evaluated (See 

subsection 

3.3.2.2.12.2)

AP-59

34 BWR/ 

PWR

Elastomer seals and 

components exposed to air –

indoor uncontrolled (internal or 

external)

Loss of material due to 

Wear

A plant specific aging 

management program is to 

be evaluated.

Yes, plant specific 

(See subsection 

3.3.2.2.13) 

A-18

A-73
NUREG-1800, Rev. 1 3.3-26 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

35 PWR Steel with stainless steel 

cladding pump casing 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 plantspecific program 

addresses cladding 

breach (See 

subsection 

3.3.2.2.14)

AP-85

36 BWR Boraflex spent fuel storage racks 

neutron-absorbing sheets 

exposed to treated water

Reduction of neutronabsorbing capacity due to 

boraflex degradation

Boraflex Monitoring No A-87

37 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

BWR Reactor Water Cleanup 

System

No A-60

38 BWR Stainless steel piping, piping 

components, and piping 

elements exposed to treated 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

BWR Stress Corrosion

Cracking and Water 

Chemistry

No A-61

39 BWR Stainless steel BWR spent fuel 

storage racks exposed to treated 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

Water Chemistry No A-96

40 BWR/ 

PWR

Steel tanks in diesel fuel oil 

system exposed to air - outdoor 

(external)

Loss of material due to 

general, pitting, and 

crevice corrosion

Aboveground Steel Tanks No A-95

41 BWR/ 

PWR

High-strength steel closure 

bolting exposed to air with steam 

or water leakage

Cracking due to cyclic 

loading, stress corrosion 

cracking

Bolting Integrity No A-04

42 BWR/ 

PWR

Steel closure bolting exposed to 

air with steam or water leakage

Loss of material due to 

general corrosion

Bolting Integrity No A-03
September 2005 3.3-27 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

43 BWR/ 

PWR

Steel bolting and closure bolting 

exposed to air – indoor 

uncontrolled (external) or air –

outdoor (External)

Loss of material due to 

general, pitting, and 

crevice corrosion

Bolting Integrity No AP-27

AP-28

44 BWR/ 

PWR

Steel compressed air system 

closure bolting exposed to 

condensation

Loss of material due to 

general, pitting, and 

crevice corrosion

Bolting Integrity No A-103

45 BWR/ 

PWR

Steel closure bolting exposed to 

air – indoor uncontrolled 

(external)

Loss of preload due to 

thermal effects, gasket 

creep, and self-loosening 

Bolting Integrity No AP-26

46 BWR/ 

PWR

Stainless steel and stainless 

clad steel piping, piping 

components, piping elements, 

and heat exchanger components 

exposed to closed cycle cooling 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

Closed-Cycle Cooling Water 

System

No A-68

AP-60

47 BWR/ 

PWR

Steel piping, piping components, 

piping elements, tanks, and heat 

exchanger components exposed 

to closed cycle cooling water

Loss of material due to 

general, pitting, and 

crevice corrosion

Closed-Cycle Cooling Water 

System

No A-25

48 BWR/ 

PWR

Steel piping, piping components, 

piping elements, tanks, and heat 

exchanger components exposed 

to closed cycle cooling water

Loss of material due to 

general, pitting, crevice, 

and galvanic corrosion

Closed-Cycle Cooling Water 

System

No A-63

49 BWR/ 

PWR

Stainless steel; steel with 

stainless steel cladding heat 

exchanger components exposed 

to closed cycle cooling water

Loss of material due to 

microbiologically 

influenced corrosion

Closed-Cycle Cooling Water 

System

No A-67

50 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping 

elements exposed to closed 

cycle cooling water

Loss of material due to 

pitting and crevice 

corrosion

Closed-Cycle Cooling Water 

System

No A-52
NUREG-1800, Rev. 1 3.3-28 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

51 BWR/ 

PWR

Copper alloy piping, piping 

components, piping elements, 

and heat exchanger components 

exposed to closed cycle cooling 

water

Loss of material due to 

pitting, crevice, and 

galvanic corrosion

Closed-Cycle Cooling Water 

System

No AP-12

AP-34

52 BWR/ 

PWR

Steel, stainless steel, and 

copper alloy heat exchanger 

tubes exposed to closed cycle 

cooling water

Reduction of heat transfer 

due to fouling

Closed-Cycle Cooling Water 

System

No AP-63

AP-77

AP-80

53 BWR/ 

PWR

Steel compressed air system 

piping, piping components, and 

piping elements exposed to 

condensation (internal)

Loss of material due to 

general and pitting 

corrosion

Compressed Air Monitoring No A-26

54 BWR/ 

PWR

Stainless steel compressed air 

system piping, piping 

components, and piping 

elements exposed to internal 

condensation

Loss of material due to 

pitting and crevice 

corrosion

Compressed Air Monitoring No AP-81

55 BWR/ 

PWR

Steel ducting closure bolting 

exposed to air – indoor 

uncontrolled (external)

Loss of material due to 

general corrosion

External Surfaces Monitoring No A-105

56 BWR/ 

PWR

Steel HVAC ducting and 

components external surfaces 

exposed to air – indoor 

uncontrolled (external)

Loss of material due to 

general corrosion

External Surfaces Monitoring No A-10

57 BWR/ 

PWR

Steel piping and components 

external surfaces exposed to air 

– indoor uncontrolled (External)

Loss of material due to 

general corrosion

External Surfaces Monitoring No A-80
September 2005 3.3-29 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

58 BWR/ 

PWR

Steel external surfaces exposed 

to air – indoor uncontrolled 

(external), air - outdoor 

(external), and condensation 

(external)

Loss of material due to 

general corrosion

External Surfaces Monitoring No A-77

A-78

A-81

59 BWR/ 

PWR

Steel heat exchanger 

components exposed to air –

indoor uncontrolled (external) or 

air -outdoor (external)

Loss of material due to 

general, pitting, and 

crevice corrosion

External Surfaces Monitoring No AP-40

AP-41

60 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

air - outdoor (external)

Loss of material due to 

general, pitting, and 

crevice corrosion

External Surfaces Monitoring No A-24

61 BWR/ 

PWR

Elastomer fire barrier penetration 

seals exposed to air – outdoor or 

air - indoor uncontrolled

Increased hardness, 

shrinkage and loss of 

strength due to 

weathering

Fire Protection No A-19

A-20

62 BWR/ 

PWR

Aluminum piping, piping 

components, and piping 

elements exposed to raw water

Loss of material due to 

pitting and crevice 

corrosion

Fire Protection No AP-83

63 BWR/ 

PWR

Steel fire rated doors exposed to 

air – outdoor or air - indoor 

uncontrolled

Loss of material due to 

Wear

Fire Protection No A-21

A-22

64 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

fuel oil

Loss of material due to 

general, pitting, and 

crevice corrosion

Fire Protection and Fuel Oil 

Chemistry

No A-28

65 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

Fire Protection and Structures 

Monitoring Program

No A-90
NUREG-1800, Rev. 1 3.3-30 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

66 BWR/ 

PWR

Reinforced concrete structural 

fire barriers – walls, ceilings and 

floors exposed to air – outdoor

Concrete cracking and 

spalling due to freeze 

thaw, aggressive 

chemical attack, and 

reaction with aggregates

Fire Protection and Structures 

Monitoring Program

No A-92

67 BWR/ 

PWR

Reinforced concrete structural 

fire barriers – walls, ceilings and 

floors exposed to air – outdoor 

or air - indoor uncontrolled

Loss of material due to 

corrosion of embedded 

steel

Fire Protection and Structures 

Monitoring Program

No A-91

A-93

68 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

raw water

Loss of material due to 

general, pitting, crevice, 

and microbiologically 

influenced corrosion, and 

fouling

Fire Water System No A-33

69 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping 

elements exposed to raw water

Loss of material due to 

pitting and crevice 

corrosion, and fouling

Fire Water System No A-55

70 BWR/ 

PWR

Copper alloy piping, piping 

components, and piping 

elements exposed to raw water

Loss of material due to 

pitting, crevice, and 

microbiologically 

influenced corrosion, and 

fouling

Fire Water System No A-45

71 BWR/ 

PWR

Steel piping, piping components, 

and piping elements exposed to 

moist air or condensation 

(Internal)

Loss of material due to 

general, pitting, and 

crevice corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No A-23

72 BWR/ 

PWR

Steel HVAC ducting and 

components internal surfaces 

exposed to condensation 

(Internal)

Loss of material due to 

general, pitting, crevice, 

and (for drip pans and 

drain lines) 

microbiologically 

influenced corrosion

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

No A-08
September 2005 3.3-31 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

73 BWR/ 

PWR

Steel crane structural girders in 

load handling system exposed to 

air- indoor uncontrolled 

(external)

Loss of material due to 

general corrosion

Inspection of Overhead 

Heavy Load and Light Load 

(Related to Refueling) 

Handling Systems

No A-07

74 BWR/ 

PWR

Steel cranes - rails exposed to 

air – indoor uncontrolled 

(external)

Loss of material due to 

Wear

Inspection of Overhead 

Heavy Load and Light Load 

(Related to Refueling) 

Handling Systems

No A-05

75 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

Open-Cycle Cooling Water 

System

No AP-75

AP-76

76 BWR/ 

PWR

Steel piping, piping 

components, and piping 

elements (without lining/coating 

or with degraded lining/coating) 

exposed to raw water

Loss of material due to 

general, pitting, crevice, 

and microbiologically 

influenced corrosion, 

fouling, and lining/coating 

degradation

Open-Cycle Cooling Water 

System

No A-38

77 BWR/ 

PWR

Steel heat exchanger 

components exposed to raw 

water

Loss of material due to 

general, pitting, crevice, 

galvanic, and 

microbiologically 

influenced corrosion, and 

fouling

Open-Cycle Cooling Water 

System

No A-64

78 BWR/ 

PWR

Stainless steel, nickel alloy, and 

copper alloy piping, piping 

components, and piping 

elements exposed to raw water

Loss of material due to 

pitting and crevice 

corrosion

Open-Cycle Cooling Water 

System

No A-43

A-53

AP-53

79 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping 

elements exposed to raw water

Loss of material due to 

pitting and crevice 

corrosion, and fouling

Open-Cycle Cooling Water 

System

No A-54
NUREG-1800, Rev. 1 3.3-32 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

80 BWR/ 

PWR

Stainless steel and copper alloy 

piping, piping components, and 

piping elements exposed to raw 

water

Loss of material due to 

pitting, crevice, and 

microbiologically 

influenced corrosion

Open-Cycle Cooling Water 

System

No AP-45

AP-55

81 BWR/ 

PWR

Copper alloy piping, piping 

components, and piping 

elements, exposed to raw water

Loss of material due to 

pitting, crevice, and 

microbiologically 

influenced corrosion, and 

fouling

Open-Cycle Cooling Water 

System

No A-44

82 BWR/ 

PWR

Copper alloy heat exchanger 

components exposed to raw 

water

Loss of material due to 

pitting, crevice, galvanic, 

and microbiologically 

influenced corrosion, and 

fouling

Open-Cycle Cooling Water 

System

No A-65

83 BWR/ 

PWR

Stainless steel and copper alloy 

heat exchanger tubes exposed 

to raw water

Reduction of heat transfer 

due to fouling

Open-Cycle Cooling Water 

System

No A-72

AP-61

84 BWR/ 

PWR

Copper alloy >15% Zn piping, 

piping components, piping 

elements, and heat exchanger 

components exposed to raw 

water, treated water, or closed 

cycle cooling water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No A-47

A-66

AP-32

AP-43

AP-65

85 BWR/ 

PWR

Gray cast iron piping, piping 

components, and piping 

elements exposed to soil, raw 

water, treated water, or closedcycle cooling water

Loss of material due to 

selective leaching

Selective Leaching of 

Materials

No A-02

A-50

A-51

AP-31

86 BWR/ 

PWR

Structural steel (new fuel storage 

rack assembly) exposed to air –

indoor uncontrolled (external)

Loss of material due to 

general, pitting, and 

crevice corrosion

Structures Monitoring 

Program

No A-94
September 2005 3.3-33 NUREG-1800, Rev. 1

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

87 PWR Boraflex spent fuel storage racks 

neutron-absorbing sheets 

exposed to treated borated 

water

Reduction of neutronabsorbing capacity due to 

boraflex degradation

Boraflex Monitoring No A-86

88 PWR Aluminum and copper alloy 

>15% Zn piping, piping 

components, and piping 

elements exposed to air with 

borated water leakage

Loss of material due to 

Boric acid corrosion

Boric Acid Corrosion No AP-1

AP-66

89 PWR Steel bolting and external 

surfaces exposed to air with 

borated water leakage

Loss of material due to 

Boric acid corrosion

Boric Acid Corrosion No A-79

A-102

90 PWR Stainless steel and steel with 

stainless steel cladding piping, 

piping components, piping 

elements, tanks, and fuel 

storage racks exposed to treated 

borated water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

Water Chemistry No A-56

A-97

AP-82

91 PWR Stainless steel and steel with 

stainless steel cladding piping, 

piping components, and piping 

elements exposed to treated 

borated water

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry No AP-79

92 BWR/ 

PWR

Galvanized steel piping, piping 

components, and piping 

elements exposed to air – indoor 

uncontrolled

None None NA - No AEM or 

AMP

AP-13
NUREG-1800, Rev. 1 3.3-34 September 2005

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

93 BWR/ 

PWR

Glass piping elements exposed 

to air, air – indoor uncontrolled 

(external), fuel oil, lubricating oil, 

raw water, treated water, and 

treated borated water

None None NA - No AEM or 

AMP

AP-14

AP-15

AP-48

AP-49

AP-50

AP-51

AP-52

94 BWR/ 

PWR

Stainless steel and nickel alloy 

piping, piping components, and 

piping elements exposed to air –

indoor uncontrolled (external)

None None NA - No AEM or 

AMP

AP-16

AP-17

95 BWR/ 

PWR

Steel and aluminum piping, 

piping components, and piping 

elements exposed to air – indoor 

controlled (external)

None None NA - No AEM or 

AMP

AP-2

AP-36

96 BWR/ 

PWR

Steel and stainless steel piping, 

piping components, and piping 

elements in concrete

None None NA - No AEM or 

AMP

AP-3

AP-19

97 BWR/ 

PWR

Steel, stainless steel, aluminum, 

and copper alloy piping, piping 

components, and piping 

elements exposed to gas

None None NA - No AEM or 

AMP

AP-6

AP-9

AP-22

AP-37

98 BWR/ 

PWR

Steel, stainless steel, and 

copper alloy piping, piping 

components, and piping 

elements exposed to dried air

None None NA - No AEM or 

AMP

AP-4

AP-8

AP-20

99 PWR Stainless steel and copper alloy 

<15% Zn piping, piping 

components, and piping 

elements exposed to air with 

borated water leakage

None None NA - No AEM or 

AMP

AP-11

AP-18
September 2005 3.3-35 NUREG-1800, Rev. 1

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

Aboveground Steel Tanks This program includes preventive measures to 

mitigate corrosion by protecting the external 

surface of steel components, per standard 

industry practice, with sealant or caulking at the 

interface of concrete and component. Visual 

inspection during periodic system walk downs 

should be sufficient to monitor degradation of the 

protective paint, coating, calking, or sealant. 

Verification of the effectiveness of the program by 

measuring the thickness of the tank bottoms 

ensures that significant degradation is not 

occurring and that the component intended 

function will be maintained during the period of 

extended operation.

Existing program

Bolting Integrity This program relies on recommendations for a 

comprehensive bolting integrity program, as 

delineated in NUREG-1339, and industry 

recommendations, as delineated in the Electric 

Power Research Institute (EPRI) NP-5769, with 

the exceptions noted in NUREG-1339 for safetyrelated bolting. The program relies on industry 

recommendations for a comprehensive bolting 

maintenance, as delineated in the EPRI TR104213 for pressure retaining bolting and 

structural bolting. The program generally includes 

periodic inspection of closure bolting for indication 

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. Other 

aging management programs, such as XI.M1, 

“ASME Section XI Inservice Inspection (ISI) 

Subsections IWB, IWC, and IWD” and XI.S3, 

“ASME Section XI Subsection IWF” also manage 

inspection of safety-related bolting and 

supplement this bolting integrity program. This 

program covers bolting within the scope of license 

renewal, including:1) safety-related bolting, 2) 

bolting for nuclear steam supply system (NSSS) 

component supports, 3) bolting for other pressure 

retaining components, including non-safety-related 

bolting, and 4) structural bolting (actual measured 

yield strength > 150 ksi).

Existing program
NUREG-1800, Rev. 1 3.3-36 September 2005

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

Boraflex Monitoring The program consists of (1) neutron attenuation 

testing (“blackness testing”) to determine gap 

formation, (2) sampling for the presence of silica in 

the spent fuel pool along with boron loss, and (3) 

monitoring and analysis of criticality to assure that 

the required 5% subcriticality margin is 

maintained. This program is implemented in 

response to GL 96-04.

Existing program

Boric Acid Corrosion This program consists of (1) visual inspection 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of leak 

path and removal of the boric acid residues, 

(3) assessment of the damage, and (4) follow-up 

inspection for adequacy. This program is 

implemented in response to GL 88-05 and recent 

operating experience.

Existing program

Buried Piping And Tanks 

Inspection

The program includes (1) preventive measures to 

mitigate corrosion, and (2) periodic inspection to 

manage the effects of corrosion on the pressureretaining capacity of buried steel piping and tanks. 

Preventive measures are in accordance with 

standard industry practice for maintaining external 

coatings and wrappings and cathodic protection. 

As an alternative, buried piping and tanks are 

inspected visually for any evidence of damage 

when they are excavated during maintenance and 

when a pipe is dug up and inspected for any 

reason with a frequency that is based on operating 

experience.

Program should 

be implemented 

before the period 

of extended 

operation.

Buried Piping And Tanks 

Surveillance

The program includes preventive measures to 

mitigate corrosion by protecting the external 

surface of buried piping and components, e.g., 

coating, wrapping, and 

a cathodic protection system. The program also 

includes surveillance and monitoring of the coating 

conductance versus time or current. This program 

is based on standard industry practices as 

described in NACE-RP-0285-95 and RP-0169-96.

Existing program

BWR Reactor Water 

Cleanup System

The program includes inservice inspection (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, Rev. 2, 

and NRC Generic Letter (GL) 88-01 and ISI in 

conformance with the American Society of 

Mechanical Engineers (ASME) Section XI.

Existing program
September 2005 3.3-37 NUREG-1800, Rev. 1

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

BWR Stress Corrosion 

Cracking

The program to manage intergranular stress 

corrosion cracking (IGSCC) in boiling water 

reactor coolant pressure boundary piping made of 

stainless steel (SS) is delineated, in part, in 

NUREG-0313, Rev. 2, and Nuclear Regulatory 

Commission (NRC) Generic Letter (GL) 88-01 and 

its Supplement 1. The program includes 

(a) preventive measures to mitigate IGSCC and 

(b) inspections to monitor IGSCC and its effects

Existing program

Closed-Cycle Cooling Water 

System 

The program relies on preventive measures to 

minimize corrosion and SCC by maintaining 

inhibitors and by performing non-chemistry 

monitoring consisting of inspection and 

nondestructive evaluations based on the 

guidelines of EPRI-TR-107396 for closed–cycle 

cooling water systems.

Existing program

Compressed Air Monitoring The program consists of inspection, monitoring, 

and testing of the entire system, including (1) 

frequent leak testing valves, piping, and other 

system components, especially those made of 

steel; and (2) preventive monitoring that checks air 

quality at various locations in the system to ensure 

that oil, water, rust, dirt, and other contaminants 

are kept within the specified limits. 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

External Surfaces 

Monitoring Program

The program is based on system inspections and 

walkdowns. This program consists of periodic 

visual inspections of components such as piping, 

piping components, ducting, and other equipment 

within the scope of license renewal and subject to 

aging management review in order to manage 

aging effects. The program manages aging effects 

through visual inspection of external surfaces for 

evidence of material loss and leakage. Loss of 

material due to boric acid corrosion is managed by 

the Boric Acid Corrosion Program. Surfaces that 

are inaccessible during plant operations are 

inspected during refueling outages. Surfaces that 

are inaccessible during both plant operations and 

refueling outages are inspected at frequencies to 

provide reasonable assurance that effect of aging 

will be managed such that applicable components 

will perform their intended function during the 

period of extended operation.

Existing program
NUREG-1800, Rev. 1 3.3-38 September 2005

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

Fire Protection The program includes a fire barrier inspection 

program and a diesel-driven fire pump inspection 

program. 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 diesel-driven 

fire pump inspection program requires that the 

pump be periodically tested to ensure that the fuel 

supply line can perform the intended function. The 

program also includes periodic inspection and test 

of halon/carbon dioxide fire suppression system. 

Existing program

Fire Water System To ensure no fouling has occurred in the fire 

protection system, periodic full flow flush test and 

system performance test are conducted to prevent 

corrosion from biofouling of components. Also, 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 

testing of water based fire protection system 

piping and components in accordance with 

applicable NFPA commitments. In addition, this 

program will be modified to included (1) portions of 

the fire protection sprinkler system that are 

subjected to full flow tests prior to the period of 

extended operation and (2) portions of the fire 

protection system exposed to water are internally 

visually inspected.

Program should 

be modified 

before the period 

of extended 

operation.

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 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
September 2005 3.3-39 NUREG-1800, Rev. 1

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components

(BWR/PWR)

The program visually inspects internal surfaces of 

steel piping, piping elements, ducting, and 

components in an internal environment (indoor 

uncontrolled air, condensation, and steam) that 

are not included in other aging management 

programs, for loss of material. Inspections are 

performed when the internal surfaces are 

accessible during the performance of periodic 

surveillance tests, during preventive maintenance 

activities or during scheduled outages. The 

program includes visual inspection to assure that 

existing environment conditions are not causing 

material degradation that could result in a loss of 

system intended functions.

Existing program

Inspection of Overhead 

Heavy Load and Light Load 

Handling System 

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 also performed to assure their integrity. 

These cranes must also comply with the 

maintenance rule requirements provided in 

10 CFR 50.65. 

Existing program

Lubricating Oil Analysis This program ensures the oil environment in the 

mechanical systems is maintained to the required 

quality. The program maintains oil systems free of 

contaminants (primarily water and particulates) 

thereby preserving an environment that is not 

conducive to loss of material, cracking, or 

reduction of heat transfer. Lubricating oil testing 

activities include sampling and analysis of 

lubricating oil for detrimental contaminants. The 

presence of water or particulates may also be 

indicative of inleakage and corrosion product 

buildup.

Existing program

One-Time Inspection This program verifies the effectiveness of other 

aging management program by determining if the 

aging effect is not occurring or the aging effect is 

progressing slowly so that the intended function 

will be maintained during the period of extended 

operation.

The inspection 

should be 

completed 

before the period 

of extended 

operation.
NUREG-1800, Rev. 1 3.3-40 September 2005

Table 3.3-2. FSAR Supplement for Aging Management of Auxiliary Systems

Program Description of Program Implementation 

Schedule*

Open-Cycle Cooling Water 

System 

The program includes (1) surveillance and control 

of biofouling, (2) tests to verify heat transfer, 

(3) routine inspection and maintenance program, 

(4) system walk down inspection, and (5) review of 

maintenance, operating, and training practices 

and procedures. The program provides assurance 

that the open-cycle cooling water system is in 

compliance with General Design Criteria and 

Quality Assurance to ensure that the open-cycle 

cooling water (or service water) system can be 

managed for an extended period of operation. 

This program is in response to NRC GL 89-13.

Existing program

Plant-Specific AMP The program should contain information 

associated with the basis for determining that 

aging effects will be managed during the period of 

extended operation.

Program should 

be implemented 

before the period 

of extended 

operation.

Selective Leaching of 

Materials

The program includes a hardness measurement of 

selected components that may be susceptible to 

selective leaching 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. For systems subjected to environments 

where water is not treated (i.e., the open-cycle 

cooling water system and the ultimate heat sinks), 

the program also follows the guidance in NRC GL 

89-13.

Program should 

be implemented 

before the period 

of extended 

operation.

Structures Monitoring

Program

The program consists of periodic inspection and 

monitoring the condition of structures and 

structure 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 NEI 93-01, Rev. 2 and 

Regulatory Guide 1.160, Rev. 2. 

Existing program

Water Chemistry This program mitigate aging effects on component 

surfaces that are exposed to water as process 

fluid, chemistry programs are used to control water 

impurities (e.g., chloride, fluoride, sulfate) that 

accelerate corrosion. The water chemistry 

program relies on monitoring and control of water 

chemistry based on EPRI guidelines.

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.
September 2005 3.4-1 NUREG-1800, Rev. 1

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 non-safety 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 

extraction steam, plant heating steam/auxiliary boiler 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.

3.4.2 Acceptance Criteria

The acceptance criteria for the areas of review describe methods for determining whether the 
NUREG-1800, Rev. 1 3.4-2 September 2005

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 line-item and the associated LRA AMP are consistent with 

the cited GALL Report AMR line-item. The reviewer should then confirm that the LRA AMR lineitem is consistent with the GALL Report AMR line-item to which it is compared.

For AMPs, 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 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.

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 apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.

3.4.2.2.1 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.

3.4.2.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion

1. Loss of material due to general, pitting and crevice corrosion could occur for steel piping, 

piping components, piping elements, tanks, and heat exchanger components exposed to 

treated water and for steel piping, piping components, and piping elements exposed to 

steam. The existing aging management program relies on monitoring and control of water 

chemistry to manage the effects of loss of material due to general, pitting, and crevice

corrosion. However, control of water chemistry does not preclude loss of material due to 

general, pitting, and crevice corrosion at locations of stagnant flow conditions. Therefore, the 
September 2005 3.4-3 NUREG-1800, Rev. 1

effectiveness of the water chemistry control program should be verified to ensure that 

corrosion is not occurring. The GALL Report recommends further evaluation of programs to 

verify the effectiveness of the water chemistry control program. A one-time inspection of 

select components and susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation. 

2. Loss of material due to general, pitting and crevice corrosion could occur for steel piping, 

piping components, and piping elements exposed to lubricating oil. The existing aging 

management program relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that is 

not conducive to corrosion. However, control of lube oil contaminants may not always have 

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil 

contaminant control should be verified to ensure that corrosion is not occurring. The GALL 

Report recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the lube oil chemistry control program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

3.4.2.2.3 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion (MIC), and Fouling

Loss of material due to general, pitting, crevice, and MIC, and fouling could occur in steel piping, 

piping components, and piping elements exposed to raw water. The GALL Report recommends 

further evaluation of a plant-specific aging management program to ensure that these aging 

effects are adequately managed. Acceptance criteria are described in Branch Technical 

Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.4.2.2.4 Reduction of Heat Transfer due to Fouling

1. Reduction of heat transfer due to fouling could occur for stainless steel and copper alloy 

heat exchanger tubes exposed to treated water. The existing aging management program 

relies on control of water chemistry to manage reduction of heat transfer due to fouling. 

However, control of water chemistry may not always have been adequate to preclude 

fouling. Therefore, the GALL Report recommends that the effectiveness of the water 

chemistry control program should be verified to ensure that reduction of heat transfer due to 

fouling is not occurring. A one-time inspection is an acceptable method to ensure that 

reduction of heat transfer is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

2. Reduction of heat transfer due to fouling could occur for steel, stainless steel, and copper 

alloy heat exchanger tubes exposed to lubricating oil. The existing aging management 

program relies on monitoring and control of lube oil chemistry to mitigate reduction of heat 

transfer due to fouling. However, control of lube oil contaminants may not always have been 

adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil contaminant

control should be verified to ensure that fouling is not occurring. The GALL Report

recommends further evaluation of programs to verify the effectiveness of lube oil chemistry 

control program. A one-time inspection of select components at susceptible locations is an 

acceptable method to determine whether an aging effect is not occurring or an aging effect 
NUREG-1800, Rev. 1 3.4-4 September 2005

is progressing very slowly such that the component’s intended function will be maintained 

during the period of extended operation.

3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion

1. Loss of material due to general, pitting and crevice corrosion, and MIC could occur in steel 

(with or without coating or wrapping) piping, piping components, piping elements and tanks 

exposed to soil. The buried piping and tanks inspection program relies on industry practice, 

frequency of pipe excavation, and operating experience to manage the effects of loss of 

material from general corrosion, pitting and crevice corrosion, and MIC. The effectiveness of 

the buried piping and tanks inspection program should be verified to evaluate an applicant's 

inspection frequency and operating experience with buried components, ensuring that loss 

of material is not occurring.

2. Loss of material due to general, pitting and crevice corrosion, and MIC could occur in steel 

heat exchanger components exposed to lubricating oil. The existing aging management 

program relies on the periodic sampling and analysis of lubricating oil to maintain 

contaminants within acceptable limits, thereby preserving an environment that is not 

conducive to corrosion. However, control of lube oil contaminants may not always have 

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil 

contaminant control should be verified to ensure that corrosion is not occurring. The GALL 

Report recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the lube oil chemistry control program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

3.4.2.2.6 Cracking due to Stress Corrosion Cracking (SCC)

Cracking due to SCC could occur in the stainless steel piping, piping components, piping 

elements, tanks, and heat exchanger components exposed to treated water greater than 60°C 

(>140°F), and for stainless steel piping, piping components, and piping elements exposed to 

steam. The existing aging management program relies on monitoring and control of water 

chemistry to manage the effects of cracking due to SCC. However, high concentrations of 

impurities at crevices and locations of stagnant flow conditions could cause SCC. Therefore, the 

GALL Report recommends that the effectiveness of the water chemistry control program should 

be verified to ensure that SCC is not occurring. A one-time inspection of selected components 

at susceptible locations is an acceptable method to ensure that SCC is not occurring and that 

the component’s intended function will be maintained during the period of extended operation.

3.4.2.2.7 Loss of Material due to Pitting and Crevice Corrosion

1. Loss of material due to pitting and crevice corrosion could occur for stainless steel, 

aluminum, and copper alloy piping, piping components and piping elements and for 

stainless steel tanks and heat exchanger components exposed to treated water. The 

existing aging management program relies on monitoring and control of water chemistry to 

manage the effects of loss of material due to pitting, and crevice corrosion. However, control 

of water chemistry does not preclude corrosion at locations of stagnant flow conditions. 

Therefore, the GALL Report recommends that the effectiveness of the water chemistry 

program should be verified to ensure that corrosion is not occurring. A one-time inspection 
September 2005 3.4-5 NUREG-1800, Rev. 1

of select components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

2. Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, 

piping components, and piping elements exposed to soil. The GALL Report recommends 

further evaluation of a plant-specific aging management to ensure that this aging effect is 

adequately managed. Acceptance criteria are described in Branch Technical Position RLSB1 (Appendix A.1 of this SRP-LR.)

3. Loss of material due to pitting and crevice corrosion could occur for copper alloy piping, 

piping components, and piping elements exposed to lubricating oil. The existing aging 

management program relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that is 

not conducive to corrosion. However, control of lube oil contaminants may not always have 

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil 

contaminant control should be verified to ensure that corrosion is not occurring. The GALL 

Report recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the lube oil chemistry control program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation.

3.4.2.2.8 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced 

Corrosion

Loss of material due to pitting, crevice, and MIC could occur in stainless steel piping, piping 

components, piping elements, and heat exchanger components exposed to lubricating oil. The 

existing aging management program relies on the periodic sampling and analysis of lubricating 

oil to maintain contaminants within acceptable limits, thereby preserving an environment that is 

not conducive to corrosion. However, control of lube oil contaminants may not always have

been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil contaminant 

control should be verified to ensure that corrosion is not occurring. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the effectiveness of 

the lube oil chemistry control program. A one-time inspection of selected components at 

susceptible locations is an acceptable method to ensure that corrosion is not occurring and that 

the component’s intended function will be maintained during the period of extended operation.

3.4.2.2.9 Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion

Loss of material due to general, pitting, crevice, and galvanic corrosion can occur for steel heat 

exchanger components exposed to treated water. The existing aging management program 

relies on monitoring and control of water chemistry to manage the effects of loss of material due 

to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude 

loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow 

conditions. Therefore, the effectiveness of the water chemistry control program should be 

verified to ensure that corrosion is not occurring. The GALL Report recommends further 

evaluation of programs to verify the effectiveness of the water chemistry control program. A 

one-time inspection of select components and susceptible locations is an acceptable method to 

ensure that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. 
NUREG-1800, Rev. 1 3.4-6 September 2005

3.4.2.2.10 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 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. Examples of the type of information to be included are provided in 

Table 3.4-2 of this SRP-LR.

3.4.3 Review Procedures

For each area of review, the following review procedures 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 

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.

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 with which the applicant is claiming to be consistent, 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 
September 2005 3.4-7 NUREG-1800, Rev. 1

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 GALL 

Report pertinent to the steam and power conversion system are summarized in Table 3.4-1 of 

this SRP-LR. In this table, the ID column provides a row identifier useful in matching the 

information presented in the corresponding table in the GALL Report, Vol. 1. The Related Item 

column identifies the item number in the GALL Report, Vol. 2, Chapters II through VIII, 

presenting detailed information summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL Report AMR line-item to which the LRA AMR 

line-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.

3.4.3.2.1 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 Loss of Material due to General, Pitting, and Crevice Corrosion

1. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting and crevice corrosion for steel piping, piping components, 

piping elements, tanks, and heat exchanger components exposed to treated water and for 

steel piping, piping components, and piping elements exposed to steam. The existing aging 

management program relies on monitoring and control of water chemistry to manage the 

effects of loss of material due to general, pitting, and crevice corrosion. However, control of 

water chemistry does not preclude corrosion from occurring at locations of stagnant flow 

conditions. Therefore, the effectiveness of the chemistry control program should be verified 

to ensure that significant degradation is not occurring and that the component’s intended 

function will be maintained during the period of extended operation. A one-time inspection of 

select components at susceptible locations is an acceptable method to determine whether 

an aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 
NUREG-1800, Rev. 1 3.4-8 September 2005

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

2. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, and crevice corrosion for steel piping, piping components, 

and piping elements exposed to lubricating oil. The existing aging management program 

relies on monitoring and control of lubricating oil contamination to maintain contaminants 

within acceptable limits. The effectiveness of lubricating oil control should be verified to 

ensure that corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

3.4.3.2.3 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion, and Fouling

The GALL Report recommends further evaluation of programs to manage the loss of material 

due to general, pitting, crevice, and MIC, and fouling for steel piping, piping components, and 

piping elements exposed to raw water. The reviewer reviews the applicant’s proposed program 

on a case-by-case basis to ensure that an adequate aging management program will be in 

place for the management of these aging effects.

3.4.3.2.4 Reduction of Heat Transfer due to Fouling

1. The GALL Report recommends further evaluation of programs to manage reduction of heat 

transfer due to fouling for stainless steel and copper alloy heat exchanger tubes exposed to 

treated water. The existing aging management program relies on control of water chemistry

to mitigate reduction of heat transfer due to fouling. However, control of water chemistry may 

not always have been adequate to preclude fouling. Therefore, the effectiveness of the 

chemistry control program should be verified to ensure that significant degradation is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. A one-time inspection of select components at susceptible locations is 

an acceptable method to determine whether an aging effect is not occurring or an aging 

effect is progressing very slowly such that the component’s intended function will be 

maintained during the period of extended operation.
September 2005 3.4-9 NUREG-1800, Rev. 1

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

2. The GALL Report recommends further evaluation of programs to manage reduction of heat 

transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger tubes 

exposed to lubricating oil. The existing aging management program relies on monitoring and 

control of lubricating oil contamination to maintain contaminants within acceptable limits. 

The effectiveness of lubricating oil control should be verified to ensure that fouling is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. A one-time inspection of select components at susceptible locations is 

an acceptable method to determine whether an aging effect is not occurring or an aging 

effect is progressing very slowly such that the component’s intended function will be 

maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed. 

3.4.3.2.5 Loss of Material due to General, Pitting, Crevice, and MicrobiologicallyInfluenced Corrosion

1. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, crevice, and MIC for steel piping, piping elements, and

piping components exposed to raw water. The reviewer reviews the applicant’s proposed 

program on a case-by-case basis to ensure that an adequate aging management program 

will be in place for the management of these aging effects. 

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to general, pitting, crevice, and MIC of steel (with or without coating or wrapping) piping, 

piping components, piping elements and tanks exposed to soil. The buried piping and tanks 
NUREG-1800, Rev. 1 3.4-10 September 2005

inspection program relies on industry practice, frequency of pipe excavation, and operating 

experience to manage the effects of loss of material from general corrosion, pitting and 

crevice corrosion, and MIC. The reviewer reviews the applicant’s program, including 

inspection frequency and operating experience with buried components, to assess the 

effectiveness of the buried piping and tanks inspection program in ensuring that corrosion is 

not occurring and that the component's intended function will be maintained during the 

period of extended operation.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to general, pitting, crevice, and MIC for steel heat exchanger components 

exposed to lubricating oil. The existing aging management program relies on monitoring and 

control of lubricating oil contamination to maintain contaminants within acceptable limits. 

The effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and that the component’s intended function will be maintained during the period of 

extended operation. A one-time inspection of select components at susceptible locations is 

an acceptable method to determine whether an aging effect is not occurring or an aging 

effect is progressing very slowly such that the component’s intended function will be 

maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

3.4.3.2.6 Cracking due to Stress Corrosion Cracking

The GALL Report recommends further evaluation of programs to manage cracking due to SCC 

of stainless steel piping, piping components, piping elements, tanks, and heat exchanger 

components exposed to treated water greater than 60°C (>140°F), and for stainless steel

piping, piping components, and piping elements exposed to steam. The existing aging 

management program relies on monitoring and control of water chemistry to manage the effects 

of cracking due to SCC. However, control of water chemistry does not preclude cracking from 

occurring at locations of stagnant flow conditions. Therefore, the effectiveness of the water 

chemistry control program should be reviewed to verify that cracking is not occurring and that 

the component’s intended function would be maintained during the period of extended 

operation. A one-time inspection of select components at susceptible locations is an acceptable 

method to determine whether an aging effect is not occurring or an aging effect is progressing 

very slowly such that the component’s intended function will be maintained during the period of 

extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to determine if 

unacceptable degradation is occurring and provide reasonable assurance that component 
September 2005 3.4-11 NUREG-1800, Rev. 1

intended functions will be maintained during the period of extended operation. If an applicant 

proposes a one-time inspection of select components and susceptible locations to ensure that 

unacceptable degradation is not occurring, the reviewer verifies (1) that the applicant’s selection 

of susceptible locations is based on appropriate considerations such as severity of conditions, 

time of service, and lowest design margin (2) that the proposed inspections will be performed 

using appropriate (volumetric and surface) techniques, for example similar to ASME Code and 

ASTM standards including visual, ultrasonic, and surface techniques (3) follow-up actions are to 

be based on the inspection results and (4) the sample size and the timing of inspections will 

provide reasonable assurance that, if unacceptable degradation is occurring, it will be found 

before applicable component intended functions can no longer be performed.

3.4.3.2.7 Loss of Material due to Pitting and Crevice Corrosion

1. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting and crevice corrosion for stainless steel piping, aluminum, and copper alloy

piping components, piping elements, and for stainless steel tanks and heat exchanger 

components exposed to treated water. The existing aging management program relies on 

monitoring and control of water chemistry to manage corrosion. However, control of water 

chemistry does not preclude corrosion from occurring at locations of stagnant flow 

conditions. Therefore, the effectiveness of the chemistry control program should be verified 

to ensure that significant degradation is not occurring and that the component’s intended 

function will be maintained during the period of extended operation. A one-time inspection of 

select components at susceptible locations is an acceptable method to determine whether 

an aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

2. The GALL Report recommends further evaluation of programs to manage loss of material 

due to pitting and crevice corrosion for stainless steel piping, piping components, piping 

elements exposed to soil. The reviewer reviews the applicant’s proposed program on a 

case-by-case basis to ensure that an adequate aging management program will be in place 

for the management of these aging effects.

3. The GALL Report recommends further evaluation of programs to manage the loss of 

material due to pitting and crevice corrosion for copper alloy piping, piping components, 

piping elements exposed to lubricating oil. The existing aging management program relies 

on monitoring and control of lubricating oil contamination to maintain contaminants within 

acceptable limits. However, control of lube oil contaminants may not always have been 
NUREG-1800, Rev. 1 3.4-12 September 2005

adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil control should 

be verified to ensure that corrosion is not occurring and that the component’s intended 

function will be maintained during the period of extended operation. A one-time inspection of 

select components at susceptible locations is an acceptable method to determine whether 

an aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to 

determine if unacceptable degradation is occurring and provide reasonable assurance that 

component intended functions will be maintained during the period of extended operation. If 

an applicant proposes a one-time inspection of select components and susceptible locations 

to ensure that unacceptable degradation is not occurring, the reviewer verifies (1) that the 

applicant’s selection of susceptible locations is based on appropriate considerations such as 

severity of conditions, time of service, and lowest design margin (2) that the proposed 

inspections will be performed using appropriate (volumetric and surface) techniques, for 

example similar to ASME Code and ASTM standards including visual, ultrasonic, and 

surface techniques (3) follow-up actions are to be based on the inspection results and (4) 

the sample size and the timing of inspections will provide reasonable assurance that, if 

unacceptable degradation is occurring, it will be found before applicable component 

intended functions can no longer be performed.

3.4.3.2.8 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced 

Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material 

due to general, pitting, crevice, and MIC for stainless steel piping, piping components, piping 

elements, and heat exchanger components exposed to lubricating oil. The existing aging 

management program relies on monitoring and control of lubricating oil contamination to 

maintain contaminants within acceptable limits. However, control of lube oil contaminants may 

not always have been adequate to preclude corrosion. Therefore, the effectiveness of 

lubricating oil control should be verified to ensure that corrosion is not occurring and that the 

component’s intended function will be maintained during the period of extended operation. A 

one-time inspection of select components at susceptible locations is an acceptable method to 

determine whether an aging effect is not occurring or an aging effect is progressing very slowly 

such that the component’s intended function will be maintained during the period of extended 

operation.

The reviewer reviews the program to confirm that it includes adequate measures to determine if 

unacceptable degradation is occurring and provide reasonable assurance that component 

intended functions will be maintained during the period of extended operation. If an applicant 

proposes a one-time inspection of select components and susceptible locations to ensure that 

unacceptable degradation is not occurring, the reviewer verifies (1) that the applicant’s selection 

of susceptible locations is based on appropriate considerations such as severity of conditions, 

time of service, and lowest design margin (2) that the proposed inspections will be performed 

using appropriate (volumetric and surface) techniques, for example similar to ASME Code and 

ASTM standards including visual, ultrasonic, and surface techniques (3) follow-up actions are to 

be based on the inspection results and (4) the sample size and the timing of inspections will 

provide reasonable assurance that, if unacceptable degradation is occurring, it will be found 

before applicable component intended functions can no longer be performed.
September 2005 3.4-13 NUREG-1800, Rev. 1

3.4.3.2.9 Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material 

due to general, pitting, crevice, and galvanic corrosion can occur for steel heat exchanger 

components exposed to treated water. The existing aging management program relies on 

monitoring and control of water chemistry to manage the effects of loss of material due to 

general, pitting, and crevice corrosion. However, control of water chemistry does not preclude 

loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow 

conditions. Therefore, the effectiveness of the chemistry control program should be verified to 

ensure that significant degradation is not occurring and that the component’s intended function 

will be maintained during the period of extended operation. A one-time inspection of select 

components at susceptible locations is an acceptable method to determine whether an aging 

effect is not occurring or an aging effect is progressing very slowly such that the component’s 

intended function will be maintained during the period of extended operation.

The reviewer reviews the program to confirm that it includes adequate measures to determine if 

unacceptable degradation is occurring and provide reasonable assurance that component 

intended functions will be maintained during the period of extended operation. If an applicant 

proposes a one-time inspection of select components and susceptible locations to ensure that 

unacceptable degradation is not occurring, the reviewer verifies (1) that the applicant’s selection 

of susceptible locations is based on appropriate considerations such as severity of conditions, 

time of service, and lowest design margin (2) that the proposed inspections will be performed 

using appropriate (volumetric and surface) techniques, for example similar to ASME Code and 

ASTM standards including visual, ultrasonic, and surface techniques (3) follow-up actions are to 

be based on the inspection results and (4) the sample size and the timing of inspections will 

provide reasonable assurance that, if unacceptable degradation is occurring, it will be found 

before applicable component intended functions can no longer be performed.

3.4.3.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

An 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, 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 an applicant chooses this option, the 

reviewer verifies that the applicant has documented such a commitment in the FSAR 

Supplement. If an 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 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).
NUREG-1800, Rev. 1 3.4-14 September 2005

3.4.3.4 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in Table 

3.4-2 in the FSAR Supplement for aging management of the steam and power conversion 

system for license renewal. The reviewer also confirms that the applicant has provided 

information equivalent to that in Table 3.4-2 in the FSAR Supplement for Subsection 3.4.3.3, 

“AMR Results Not Consistent with or Not Addressed in GALL Report.” 

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 3.4-2, 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.
September 2005 3.4-15 NUREG-1800, Rev. 1

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, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.
NUREG-1800, Rev. 1 3.4-16 September 2005

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

1 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to steam or 

treated water

Cumulative fatigue 

damage

TLAA, evaluated in 

accordance with 10 

CFR 54.21(c)

Yes, TLAA (See 

subsection 3.4.2.2.1)

S-08

S-11

2 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to steam

Loss of material due to 

general, pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.2.1)

S-04

S-06

3 PWR Steel heat exchanger components 

exposed to treated water

Loss of material due to 

general, pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.2.1)

S-19

4 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to treated 

water

Loss of material due to 

general, pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.2.1)

S-09

S-10

5 BWR Steel heat exchanger components 

exposed to treated water

Loss of material due to 

general, pitting, crevice, 

and galvanic corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.2.9)

S-18

6 BWR/ 

PWR

Steel and stainless steel tanks 

exposed to treated water

Loss of material due to 

general (steel only) 

pitting and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.7.1, except for 

steel tanks see 

subsection 3.4.2.2.2.1)

S-13

7 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to 

lubricating oil

Loss of material due to 

general, pitting and 

crevice corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.2.2)

SP-25
September 2005 3.4-17 NUREG-1800, Rev. 1

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

8 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to raw 

water

Loss of material due to 

general, pitting, crevice, 

and microbiologicallyinfluenced corrosion, 

and fouling

Plant specific Yes, plant specific (See 

subsection 3.4.2.2.3)

S-12

9 BWR/ 

PWR

Stainless steel and copper alloy heat 

exchanger tubes exposed to treated 

water

Reduction of heat 

transfer due to fouling

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.4.1)

SP-40

SP-58

10 BWR/ 

PWR

Steel, stainless steel, and copper 

alloy heat exchanger tubes exposed 

to lubricating oil

Reduction of heat 

transfer due to fouling

Lubricating Oil 

Analysis and OneTime Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.4.2)

SP-53

SP-62

SP-63

11 BWR/ 

PWR

Buried steel piping, piping 

components, piping elements, and 

tanks (with or without coating or 

wrapping) exposed to soil

Loss of material due to 

general, pitting, crevice, 

and microbiologicallyinfluenced corrosion

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection

No 

Yes, detection of aging 

effects and operating 

experience are to be 

further evaluated (See 

subsection 3.4.2.2.5.1) 

S-01

12 BWR/ 

PWR

Steel heat exchanger components 

exposed to lubricating oil

Loss of material due to 

general, pitting, crevice, 

and microbiologicallyinfluenced corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.5.2)

S-17

13 BWR Stainless steel piping, piping 

components, piping elements 

exposed to steam

Cracking due to stress 

corrosion cracking

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.6)

SP-45
NUREG-1800, Rev. 1 3.4-18 September 2005

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

14 BWR/ 

PWR

Stainless steel piping, piping 

components, piping elements, tanks, 

and heat exchanger components 

exposed to treated water >60°C 

(>140°F)

Cracking due to stress 

corrosion cracking

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.6)

S-39

SP-17

SP-19

SP-42

15 BWR/ 

PWR

Aluminum and copper alloy piping, 

piping components, and piping 

elements exposed to treated water

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.7.1)

SP-24

SP-61

16 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements; 

tanks, and heat exchanger 

components exposed to treated 

water

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.7.1)

S-21

S-22

SP-16

17 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to soil

Loss of material due to 

pitting and crevice 

corrosion

Plant specific Yes, plant specific (See 

subsection 3.4.2.2.7.2) 

SP-37

18 BWR/ 

PWR

Copper alloy piping, piping 

components, and piping elements 

exposed to lubricating oil

Loss of material due to 

pitting and crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.7.3)

SP-32

19 BWR/ 

PWR

Stainless steel piping, piping 

components, piping elements, and 

heat exchanger components 

exposed to lubricating oil

Loss of material due to

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes, detection of aging 

effects is to be evaluated 

(See subsection 

3.4.2.2.8)

S-20

SP-38

20 BWR/ 

PWR

Steel tanks exposed to air – outdoor 

(external)

Loss of material/ 

general, pitting, and 

crevice corrosion

Aboveground Steel 

Tanks

No S-31

21 BWR/ 

PWR

High-strength steel closure bolting 

exposed to air with steam or water 

leakage

Cracking due to cyclic 

loading, stress corrosion 

cracking

Bolting Integrity No S-03
September 2005 3.4-19 NUREG-1800, Rev. 1

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

22 BWR/ 

PWR

Steel bolting and closure bolting 

exposed to air with steam or water 

leakage, air – outdoor (external), or 

air – indoor uncontrolled (external); 

Loss of material due to 

general, pitting and 

crevice corrosion; loss of 

preload due to thermal 

effects, gasket creep, 

and self-loosening 

Bolting Integrity No S-02

S-32

S-33

S-34

23 BWR/ 

PWR

Stainless steel piping, piping 

components, and piping elements 

exposed to closed-cycle cooling 

water >60°C (>140°F)

Cracking due to stress 

corrosion cracking

Closed-Cycle 

Cooling Water 

System

No SP-54

24 BWR/ 

PWR

Steel heat exchanger components 

exposed to closed cycle cooling 

water

Loss of material due to 

general, pitting, crevice, 

and galvanic corrosion

Closed-Cycle 

Cooling Water 

System

No S-23

25 BWR/ 

PWR

Stainless steel piping, piping 

components, piping elements, and 

heat exchanger components 

exposed to closed cycle cooling 

water

Loss of material due to 

pitting and crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No S-25

SP-39

26 BWR/ 

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

Closed-Cycle 

Cooling Water 

System

No SP-8

27 BWR/ 

PWR

Steel, stainless steel, and copper 

alloy heat exchanger tubes exposed 

to closed cycle cooling water

Reduction of heat 

transfer due to fouling

Closed-Cycle 

Cooling Water 

System

No SP-41

SP-57

SP-64

28 BWR/ 

PWR

Steel external surfaces exposed to 

air – indoor uncontrolled (external), 

condensation (external), or air 

outdoor (external)

Loss of material due to 

general corrosion

External Surfaces 

Monitoring

No S-29

S-41

S-42

29 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to steam or 

treated water

Wall thinning due to 

flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion 

No S-15

S-16
NUREG-1800, Rev. 1 3.4-20 September 2005

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

30 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to air 

outdoor (internal) or condensation 

(internal)

Loss of material due to 

general, pitting, and 

crevice corrosion

Inspection of Internal 

Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No SP-59

SP-60

31 BWR/ 

PWR

Steel heat exchanger components 

exposed to raw water

Loss of material due to 

general, pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced corrosion, 

and fouling

Open-Cycle Cooling 

Water System

No S-24

32 BWR/ 

PWR

Stainless steel and copper alloy 

piping, piping components, and 

piping elements exposed to raw 

water

Loss of material due to 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Open-Cycle Cooling 

Water System

No SP-31

SP-36

33 BWR/ 

PWR

Stainless steel heat exchanger 

components exposed to raw water

Loss of material due to 

pitting, crevice, and 

microbiologicallyinfluenced corrosion, 

and fouling

Open-Cycle Cooling 

Water System

No S-26

34 BWR/ 

PWR

Steel, stainless steel, and copper 

alloy heat exchanger tubes exposed 

to raw water

Reduction of heat 

transfer due to fouling

Open-Cycle Cooling 

Water System

No S-27

S-28

SP-56

35 BWR/ 

PWR

Copper alloy >15% Zn piping, piping 

components, and piping elements 

exposed to closed cycle cooling 

water, raw water, or treated water

Loss of material due to 

selective leaching

Selective Leaching 

of Materials

No SP-29

SP-30

SP-55

36 BWR/ 

PWR

Gray cast iron piping, piping 

components, and piping elements

exposed to soil, treated water, or raw 

water

Loss of material due to 

selective leaching

Selective Leaching 

of Materials

No SP-26

SP-27

SP-28
September 2005 3.4-21 NUREG-1800, Rev. 1

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

Evaluated in Chapter VIII of the GALL Report

ID Type Component Aging 

Effect/Mechanism

Aging Management 

Programs

Further Evaluation 

Recommended

Related 

Item

37 BWR/ 

PWR

Steel, stainless steel, and nickelbased alloy piping, piping 

components, and piping elements 

exposed to steam

Loss of material due to 

pitting and crevice 

corrosion

Water Chemistry No S-05

S-07

SP-18

SP-43

SP-46

38 PWR Steel bolting and external surfaces 

exposed to air with borated water 

leakage

Loss of material due to 

boric acid corrosion

Boric Acid Corrosion No S-30

S-40

39 PWR Stainless steel piping, piping 

components, and piping elements 

exposed to steam

Cracking due to stress 

corrosion cracking

Water Chemistry No SP-44

40 BWR/ 

PWR

Glass piping elements exposed to 

air, lubricating oil, raw water, and 

treated water

None None NA - No AEM or AMP SP-9

SP-10

SP-33

SP-34

SP-35

41 BWR/ 

PWR

Stainless steel, copper alloy, and 

nickel alloy piping, piping 

components, and piping elements 

exposed to air – indoor uncontrolled 

(external)

None None NA - No AEM or AMP SP-6

SP-11

SP-12

42 BWR/ 

PWR

Steel piping, piping components, and 

piping elements exposed to air –

indoor controlled (external)

None None NA - No AEM or AMP SP-1

43 BWR/ 

PWR

Steel and stainless steel piping, 

piping components, and piping 

elements in concrete

None None NA - No AEM or AMP SP-2

SP-13

44 BWR/ 

PWR

Steel, stainless steel, aluminum, and 

copper alloy piping, piping 

components, and piping elements 

exposed to gas

None None NA - No AEM or AMP SP-4

SP-5

SP-15

SP-23
NUREG-1800, Rev. 1 3.4-22 September 2005

Table 3.4-2 FSAR Supplement for Aging Management of Steam and Power 

Conversion System

Program Description of Program Implementation 

Schedule*

Aboveground Steel 

Tanks

This program includes preventive measures to 

mitigate corrosion by protecting the external surface 

of steel components, per standard industry practice, 

with sealant or caulking at the interface of concrete 

and component. Visual inspection during periodic 

system walk downs should be sufficient to monitor 

degradation of the protective paint, coating, calking, 

or sealant. Verification of the effectiveness of the 

program by measuring the thickness of the tank 

bottoms ensures that significant degradation is not 

occurring and that the component intended function 

will be maintained during the period of extended 

operation.

Existing program

Bolting Integrity This program consists of guidelines on materials 

selection, strength and hardness properties, 

installation procedures, lubricants, and sealants, 

corrosion considerations in the selection and 

installation of pressure-retaining bolting for nuclear 

applications, and enhanced inspection techniques. 

This program relies on the bolting integrity program 

delineated in NUREG-1339 and industry’s 

recommendations delineated in EPRI NP-5769, with 

the exceptions noted in NUREG-1339 for safetyrelated bolting and in EPRI TR -104213 for pressure 

retaining bolting and structural bolting. 

Existing program

Boric Acid Corrosion This program consists of (1) visual inspection 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of leak 

path and removal of the boric acid residues, 

(3) assessment of the damage, and (4) follow-up 

inspection for adequacy. This program is 

implemented in response to GL 88-05 and recent 

operating experience.

Existing program

Buried Piping and 

Tanks Inspection

This program includes (a) preventive measures to 

mitigate corrosion, and (b) periodic inspection to 

manage the effects of corrosion on the pressureretaining capacity of buried steel piping and tanks. 

Preventive measures are in accordance with 

standard industry practice for maintaining external 

coatings and wrappings and cathodic protection. As 

an alternative, buried piping and tanks are inspected 

when they are excavated during maintenance and 

when a pipe is dug up and inspected for any reason 

with a frequency that is based on operating 

experience.

Program should be 

implemented before 

the period of 

extended operation.
September 2005 3.4-23 NUREG-1800, Rev. 1

Table 3.4-2 FSAR Supplement for Aging Management of Steam and Power 

Conversion System

Program Description of Program Implementation 

Schedule*

Buried Piping and 

Tanks Surveillance

This program includes preventive measures to 

mitigate corrosion by protecting the external surface 

of buried piping and components, e.g., coating, 

wrapping, and a cathodic protection system. The 

program also includes surveillance and monitoring 

of the coating conductance versus time or current. 

This program is based on standard industry 

practices as described in NACE-RP-01-69.

Existing program

Closed-Cycle 

Cooling Water 

System

This program relies on preventive measures to 

minimize corrosion and SCC by maintaining 

inhibitors and by performing non-chemistry 

monitoring consisting of inspection and 

nondestructive evaluations based on the guidelines 

of EPRI-TR-107396 for closed-cycle cooling water 

systems.

Existing program

External Surfaces 

Monitoring Program

This program is based on system inspections and 

walkdowns. This program consists of periodic visual 

inspections of components such as piping, piping 

components, ducting, and other equipment within 

the scope of license renewal and subject to aging 

management review in order to manage aging 

effects. The program manages aging effects through 

visual inspection of external surfaces for evidence of 

loss of material. Loss of material due to boric acid 

corrosion is managed by the Boric Acid Corrosion 

Program. Surfaces that are inaccessible during plant 

operations are inspected during refueling outages. 

Surfaces that are inaccessible during both plant 

operations and refueling outages are inspected at 

frequencies to provide reasonable assurance that 

effect of aging will be managed such that applicable 

components will perform their intended function 

during the period of extended operation.

Existing program

Flow-Accelerated 

Corrosion

This program consists of (1) conduct appropriate 

analysis and baseline inspection, (2) determine 

extent of thinning, and replace/repair components, 

and (3) perform follow-up inspections to confirm or 

quantify and take longer-term corrective actions. 

The program relies on implementation of EPRI 

guidelines of NSAC-202L-R2. 

Existing program
NUREG-1800, Rev. 1 3.4-24 September 2005

Table 3.4-2 FSAR Supplement for Aging Management of Steam and Power 

Conversion System

Program Description of Program Implementation 

Schedule*

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components

This program visually inspects internal surfaces of 

steel piping, piping elements, ducting, and 

components in an internal environment (indoor 

uncontrolled air, condensation, and steam) that are 

not included in other aging management programs

for loss of material. Inspections are performed when 

the internal surfaces are accessible during the 

performance of periodic surveillance tests, during 

preventive maintenance activities or during 

scheduled outages. The program includes visual 

inspection to assure that existing environment 

conditions are not causing material degradation that 

could result in a loss of system intended functions. 

Existing program

Lubricating Oil 

Analysis

This program ensures the oil environment in the 

mechanical systems is maintained to the required 

quality. This program maintains oil systems free of 

contaminants (primarily water and particulates) 

thereby preserving an environment that is not 

conducive to loss of material, cracking, or reduction 

of heat transfer. Lubricating oil testing activities 

include sampling and analysis of lubricating oil for 

detrimental contaminants. The presence of water or 

particulates may also be indicative of inleakage and 

corrosion product buildup.

Existing program

One-Time Inspection This program verifies the effectiveness of other 

aging management program by determining if the 

aging effect is not occurring or the aging effect is 

progressing slowly so that the intended function will 

be maintained during the period of extended 

operation.

The inspection 

should be 

completed before 

the period of 

extended operation. 

Open-Cycle Cooling 

Water System

This program includes (a) surveillance and control of 

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

inspection and maintenance program, (d) system 

walk down inspection, and (e) review of 

maintenance, operating, and training practices and 

procedures. The program provides assurance that 

the open-cycle cooling water system is in 

compliance with General Design Criteria and Quality 

Assurance to ensure that the open-cycle cooling 

water (or service water) system can be managed for 

an extended period of operation. This program is in 

response to NRC GL 89-13.

Existing program

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 before 

the period of 

extended operation.
September 2005 3.4-25 NUREG-1800, Rev. 1

Table 3.4-2 FSAR Supplement for Aging Management of Steam and Power 

Conversion System

Program Description of Program Implementation 

Schedule*

Quality Assurance The 10 CFR Part 50, Appendix B program provides 

for corrective actions, the confirmation process, and 

administrative controls for aging management 

programs for license renewal. The scope of this 

existing program will be expanded to include 

nonsafety-related structures and components that 

are subject to an aging management review for 

license renewal.

Program should be 

implemented before 

the period of 

extended operation.

Water Chemistry This program mitigate aging effects on component 

surfaces that are exposed to water as process fluid, 

chemistry programs are used to control water 

impurities (e.g., chloride, fluoride, sulfate) that 

accelerate corrosion. The water chemistry program 

relies on monitoring and control of water chemistry 

based on EPRI guidelines.

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.
NUREG-1800, Rev. 1 3.4-26 September 2005

This Page Intentionally Left Blank
September 2005 3.5-1 NUREG-1800, Rev. 1

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) (Ref. 1). 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 containments (Ref. 2). 

The safety-related and other structures (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 tanks and 

missile barriers; and Group 9: BWR unit vent stack (Ref. 2).

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) (Ref. 2).

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. 1 3.5-2 September 2005

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 line-item and the associated LRA AMP are consistent with the cited 

GALL Report AMR line-item. The staff reviewer should then confirm that the LRA AMR line-item 

is consistent with the GALL Report AMR line-item to which it is compared. 

For AMPs, if the applicant identifies an exception to the cited GALL 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 AMP with all exceptions would satisfy the criteria of 10 

CFR 54.21(a)(3). If, while reviewing the 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 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.

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 apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.
September 2005 3.5-3 NUREG-1800, Rev. 1

3.5.2.2.1 PWR and BWR Containments

3.5.2.2.1.1 Aging of Inaccessible Concrete Areas 

Increases in porosity and permeability, cracking, loss of material (spalling, scaling) due to 

aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel could occur in inaccessible areas of PWR and BWR 

concrete and steel containments. The existing program relies on ASME Section XI, Subsection 

IWL to manage these aging effects. However, the GALL Report recommends further evaluation 

of plant - specific programs to manage the aging effects for inaccessible areas if the 

environment is aggressive. Acceptance criteria are described in Branch Technical Position 

RLSB-1 (Appendix A.1 of this SRP-LR).

3.5.2.2.1.2 Cracks and Distortion due to Increased Stress Levels from Settlement; 

Reduction of Foundation Strength, Cracking and Differential Settlement due 

to Erosion of Porous Concrete Subfoundations, if Not Covered by Structures 

Monitoring Program

Cracks and distortion due to increased stress levels from settlement could occur in PWR and 

BWR concrete and steel containments. Also, reduction of foundation strength, cracking, and 

differential settlement due to erosion of porous concrete subfoundations could occur in all types 

of PWR and BWR containments. The existing program relies on structures monitoring program 

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 within the scope of the applicant’s structures monitoring program.

3.5.2.2.1.3 Reduction of Strength and Modulus of Concrete Structures 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-3400 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). Acceptance criteria are described in Branch Technical Position 

RLSB-1 (Appendix A.1 of this SRP-LR).

3.5.2.2.1.4 Loss of Material due to General, Pitting and Crevice Corrosion 

Loss of material due to general, pitting and crevice corrosion could occur in steel elements of 

accessible and inaccessible areas for all types of PWR and BWR containments. The existing 

program relies on ASME Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J, to 

manage this aging effect. The GALL Report recommends further evaluation of plant-specific 

programs to manage this aging effect for inaccessible areas if corrosion is significant. 

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).
NUREG-1800, Rev. 1 3.5-4 September 2005

3.5.2.2.1.5 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.

3.5.2.2.1.6 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. 

3.5.2.2.1.7 Cracking due to Stress Corrosion Cracking (SCC)

Cracking due to stress corrosion cracking of stainless steel penetration sleeves, penetration 

bellows, and dissimilar metal welds could occur in all types of PWR and BWR containments. 

Cracking due to SCC could also occur in stainless steel vent line bellows for 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 sleeves, penetration bellows and dissimilar metal 

welds, and stainless steel vent line bellows. 

3.5.2.2.1.8 Cracking due to Cyclic Loading

Cracking due to cyclic loading of suppression pool steel and stainless steel shells (including 

welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, and 

penetration bellows) could occur for all types of PWR and BWR containments and BWR vent 

header, vent line bellows and downcomers. The existing program relies on ASME Section XI, 

Subsection IWE and 10 CFR Part 50, Appendix J to manage this aging effect. However, VT-3 

visual inspection may not detect fine cracks. The GALL Report recommends further evaluation 

for detection of this aging effect.

3.5.2.2.1.9 Loss of Material (Scaling, Cracking, and Spalling) due to Freeze-Thaw

Loss of material (scaling, cracking, and spalling) due to freeze-thaw could occur in PWR and 

BWR concrete containments. The existing program relies on ASME Section XI, Subsection IWL 

to manage this aging effect. The GALL Report recommends further evaluation of this aging 

effect for plants located in moderate to severe weathering conditions.
September 2005 3.5-5 NUREG-1800, Rev. 1

3.5.2.2.1.10 Cracking due to Expansion and Reaction with Aggregate, and Increase in 

Porosity and Permeability due to Leaching of Calcium Hydroxide

Cracking due to expansion and reaction with aggregate, and increase in porosity and 

permeability due to leaching of calcium hydroxide could occur in concrete elements of PWR and 

BWR concrete and steel containments. The existing program relies on ASME Section XI, 

Subsection IWL to manage these aging effects. The GALL Report recommends further 

evaluation if concrete was not constructed in accordance with the recommendations in ACI 

201.2R-77.

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

3.5.2.2.2.1 Aging of Structures Not Covered by Structures Monitoring Program

The GALL Report recommends further evaluation of certain structure/aging effect combinations 

if they are not covered by the structures monitoring program. This includes (1) cracking, loss of 

bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 

7, 9 structures; (2) increase in porosity and permeability, cracking, loss of material (spalling, 

scaling) due to aggressive chemical attack for Groups 1-5, 7, 9 structures; (3) loss of material 

due to corrosion for Groups 1-5, 7, 8 structures; (4) loss of material (spalling, scaling) and 

cracking due to freeze-thaw for Groups 1-3, 5, 7-9 structures; (5) cracking due to expansion and 

reaction with aggregates for Groups 1-5, 7-9 structures; (6) cracks and distortion due to 

increased stress levels from settlement for Groups 1-3, 5-9 structures; and (7) reduction in 

foundation strength, cracking, differential settlement due to erosion of porous concrete 

subfoundation for Groups 1-3, 5-9 structures. The GALL Report recommends further evaluation 

only for structure/aging effect combinations that are not within the structures monitoring 

program. 

Lock up due to wear could occur for Lubrite® radial beam seats in BWR drywell, RPV support 

shoes for PWR with nozzle supports, steam generator supports, and other sliding support 

bearings and sliding support surfaces. The existing program relies on the structures monitoring 

program or ASME Section XI, Subsection IWF to manage this aging effect. The GALL Report 

recommends further evaluation only for structure/aging effect combinations that are not within 

the ISI (IWF) or structures monitoring program.

3.5.2.2.2.2 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 ACI 201.2R-77.

3. Cracks and distortion due to increased stress levels from settlement and reduction of 

foundation strength, cracking, and differential settlement due to erosion of porous concrete 

subfoundations could occur in below-grade inaccessible concrete areas of Groups 1-3, 5 

and 7-9 structures. The existing program relies on structures monitoring program to manage 
NUREG-1800, Rev. 1 3.5-6 September 2005

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, cracking, loss of material (spalling, scaling) due to 

aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel could occur in below-grade inaccessible 

concrete areas of Groups 1-3, 5 and 7-9 structures. The GALL Report recommends further 

evaluation of plant-specific programs to manage these aging effects in inaccessible areas of 

these Groups of structures if the environment is aggressive. The acceptance criteria are 

described in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

5. Increase in porosity and permeability, and loss of strength due to leaching of calcium 

hydroxide could occur in below-grade inaccessible concrete areas of Groups 1-3, 5 and 7-9 

structures. The GALL Report recommends further evaluation of this aging effect for

inaccessible areas of these Groups of structures if concrete was not constructed in 

accordance with the recommendations in ACI 201.2R-77.

3.5.2.2.2.3 Reduction of Strength and Modulus of Concrete Structures 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 150°F except for local areas, which are allowed to have 

increased temperatures not to exceed 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). The acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).

. 

3.5.2.2.2.4 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 the FERC / US 

Army Corp of Engineers dam inspections and maintenance. 

1. Increase in porosity and permeability, cracking, loss of material (spalling, scaling)/ 

aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, 

scaling)/ corrosion of embedded steel could occur in below-grade inaccessible concrete 

areas of Group 6 structures. The GALL Report recommends further evaluation of plantspecific programs to manage these aging effects in inaccessible areas if the environment is 

aggressive. The acceptance criteria are described in Branch Technical Position RLSB-1 

(Appendix A.1 of this SRP-LR). 
September 2005 3.5-7 NUREG-1800, Rev. 1

2. 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.

3. Cracking due to expansion and reaction with aggregates and increase in porosity and 

permeability, and loss of strength due to leaching of calcium hydroxide could occur in belowgrade inaccessible reinforced concrete areas of Group 6 structures. The GALL Report 

recommends further evaluation of inaccessible areas if concrete was not constructed in 

accordance with the recommendations in ACI 201.2R-77.

3.5.2.2.2.5 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).

3.5.2.2.2.6 Aging of Supports Not Covered by Structures Monitoring Program

The GALL Report recommends further evaluation of certain component support/aging effect 

combinations if they are not covered by the structures monitoring program. This includes (1) 

loss of material due to general and pitting corrosion, for Groups B2-B5 supports; (2) reduction in 

concrete anchor capacity due to degradation of the surrounding concrete, for Groups B1-B5

supports; and (3) reduction/loss of isolation function due to degradation of vibration isolation 

elements, for Group B4 supports. Further evaluation is necessary only for structure/aging effect 

combinations not covered by the structures monitoring program. 

3.5.2.2.2.7 Cumulative Fatigue Damage due to Cyclic Loading

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 GALL Report

Acceptance criteria are described in Branch Technical Position RLSB-1 (Appendix A.1 of this 

SRP-LR).

3.5.2.4 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 
NUREG-1800, Rev. 1 3.5-8 September 2005

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. Examples of the type of information required are provided in Table 3.5-2 of 

this SRP-LR.

3.5.3 Review Procedures

For each area of review, the following review procedures 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 

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 GALL as applicable to its plant.

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 the GALL Report AMP to 

which it is claiming to be consistent, 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 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 GALL pertinent to the 

structures and component supports are summarized in Table 3.5-1 of this SRP-LR. In this table, 

the ID column provides a row identifier useful in matching the information presented in the 

corresponding table in the GALL Report Vol. 1. The Related Item column identifies the item 

number in the GALL Report Vol. 2, Chapters II through VIII, presenting detailed information 

summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL AMR line-item to which the LRA AMR line-item 

is compared identifies that further evaluation is recommended, then additional criteria apply as 
September 2005 3.5-9 NUREG-1800, Rev. 1

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 Aging of Inaccessible Concrete Areas

The GALL Report recommends further evaluation of programs to manage aging effects in 

inaccessible areas if the environment is aggressive. Possible aging effects are increases in

porosity and permeability, cracking and loss of material (spalling, scaling) due to aggressive 

chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to 

corrosion of embedded steel in PWR and BWR concrete and steel containments. The current 

aging management programs that involve detecting the aging effects for inaccessible areas 

consist of Section XI, Subsection IWL examinations of 1992 or later edition of ASME code 

(Ref. 3), which is in accordance with the requirements of, and is approved in 10 CFR 50.55a. 

However, Subsection IWL exempts from examination portions of the concrete containments that

are inaccessible (e.g., foundation, exterior walls below grades, concrete covered by liner). 

To cover the inaccessible areas, 10 CFR 50.55a(b)(2)(ix) requires that the applicant evaluate 

the acceptability of inaccessible areas when conditions exist in accessible areas that could 

indicate the presence of, or result in, degradation to such inaccessible areas. In addition, the 

GALL Report recommends further evaluation to manage these aging effects for inaccessible 

areas if the below-grade environment is aggressive. Periodic monitoring of below-grade water 

chemistry (including consideration of potential seasonal variations) is an acceptable approach to 

demonstrate that the below-grade environment is aggressive or non-aggressive. The GALL 

Report recommends that examination of representative samples of below-grade concrete, when 

excavated for any reason, be performed. The reviewer reviews the applicant’s proposed aging 

management program to determine that, where appropriate, an effective inspection program will 

be implemented to ensure that these aging effects in inaccessible areas are adequately 

managed during the period of extended operation. 

3.5.3.2.1.2 Cracks and distortion due to increased stress levels from settlement; 

Reduction of Foundation Strength, Cracking, and Differential Settlement due 

to Erosion of Porous Concrete Subfoundations, if Not Covered by Structures 

Monitoring Program

The GALL Report recommends aging management of (1) cracks 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, cracking, and differential settlement due to erosion of 

porous concrete subfoundations for all types of PWR and BWR containments if not within the 

scope of structures monitoring program. Also, if a de-watering system is relied upon for control 

of settlement and erosion, then proper functioning of the de-watering system should be 

monitored for the period of extended operation. 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 structures monitoring program. If 

not, the reviewer evaluates the plant-specific program for monitoring the de-watering system 

during the period of extended operation. 
NUREG-1800, Rev. 1 3.5-10 September 2005

3.5.3.2.1.3 Reduction of Strength and Modulus of Concrete Structures 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 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 reviewer reviews and confirms that the applicant’s discussion in the renewal application 

indicates that the affected PWR and BWR containment components are not exposed to 

temperature that exceeds the temperature limits. For concrete containment components that 

operate above these temperature limits, the reviewer reviews the applicant’s proposed 

programs on a case-by-case basis to ensure that the effects of elevated temperature will be 

managed during the period of extended operation.

3.5.3.2.1.4 Loss of Material due to General, Pitting and Crevice Corrosion 

The GALL Report identifies programs to manage loss of material due to general, pitting and 

crevice corrosion in accessible and inaccessible areas of the steel elements in drywell and torus 

or the steel liner and integral attachments for all types of PWR and BWR containments. The 

aging management program consists of ASME Section XI, Subsection IWE (Ref. 4), 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. 

3.5.3.2.1.5 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.

3.5.3.2.1.6 Cumulative Fatigue Damage

Fatigue analyses included in current licensing basis for the containment liner plate and 

penetrations are TLAAs as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 
September 2005 3.5-11 NUREG-1800, Rev. 1

accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in 

Section 4.6 of this SRP-LR.

3.5.3.2.1.7 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 and BWR vent headers, vent line bellows, and 

downcomers. 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. 

5.5.3.2.1.8 Cracking due to Cyclic Loading

The GALL Report recommends further evaluation of programs to manage cracking due to cyclic 

loading of steel and stainless steel penetration bellows and dissimilar metal welds in all types of 

PWR and BWR containments and BWR suppression pool shell and downcomers. Containment 

ISI IWE and leak rate testing may not be sufficient to detect fine cracks, especially for 

penetration bellows. VT-3 visual examination may not detect fine cracks. The reviewer reviews 

and evaluates the applicant’s proposed program to confirm that adequate inspection methods 

will be implemented to ensure that fine cracks are detected.

3.5.3.2.1.9 Loss of Material (Scaling, Cracking, and Spalling due to Freeze-Thaw) 

The GALL Report recommends further evaluation of programs to manage loss of material 

(scaling, cracking, and spalling) 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, 

Ref. 7). Documented evidence confirms that where the existing concrete had air content of 3% 

to 6%, subsequent inspection did not exhibit degradation related to freeze-thaw. Such 

inspections should be considered a part of the evaluation. The weathering index for the 

continental US is shown in ASTM C33-90, Fig. 1. 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.

3.5.3.2.1.10 Cracking due to Expansion and Reaction with Aggregate, and Increase in 

Porosity and Permeability due to Leaching of Calcium Hydroxide

The GALL Report recommends further evaluation of programs to manage cracking due to 

expansion and reaction with aggregate, and increase in porosity and permeability due to 

leaching of calcium hydroxide in concrete elements of PWR and BWR concrete and steel 

containments. The GALL Report recommends containment ISI Subsection IWL to manage 
NUREG-1800, Rev. 1 3.5-12 September 2005

these aging effects. An aging management program is not necessary, even if reinforced 

concrete is exposed to flowing water, if there is documented evidence that confirms the in-place 

concrete was constructed in accordance with the recommendations in ACI 201.2R-77 (Ref. 8). 

The reviewer should confirm that the applicant has satisfied the 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 these aging effects in 

inaccessible areas for concrete that was not constructed in accordance with the 

recommendations of ACI 201.2R-77 are adequately managed.

3.5.3.2.2 Safety-Related and Other Structures, and Component Supports

3.5.3.2.2.1 Aging of Structures Not Covered by Structures Monitoring Program

The GALL Report recommends further evaluation of certain structure/aging effect combinations 

if they are not covered by the structures monitoring program. This includes (1) cracking, loss of 

bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 

7, 9 structures, (2) increase in porosity and permeability, cracking, loss of material (spalling, 

scaling) due to aggressive chemical attack for Groups 1-5, 7, 9 structures, (3) loss of material 

due to corrosion for Groups 1-5, 7, 8 structures, (4) loss of material (spalling, scaling) and 

cracking due to freeze-thaw for Groups 1-3, 5, 7-9 structures, (5) cracking due to expansion and 

reaction with aggregates for Groups 1-5, 7-9 structures, (6) cracks and distortion due to 

increased stress levels from settlement for Groups 1-3, 5-9 structures, and (7) reduction in 

foundation strength, cracking, differential settlement due to erosion of porous concrete 

subfoundation for Groups 1-3, 5-9 structures. Further evaluation is necessary only for 

structure/aging effect combinations not covered by the structures monitoring program. In 

addition, the GALL Report recommends further evaluation of structure/aging effect combination 

of lock-up due to wear of Group 4 Lubrite® components if they are not covered by either the 

ASME Section XI, Subsection IWF or the structures monitoring program.

The aging management program consists of a structures monitoring program to confirm that the 

CLB is maintained through periodic testing and inspection of critical plant structures, systems, 

and components. The reviewer confirms that the applicant has identified the structure/aging 

effect combinations not within the scope of the applicant’s structures monitoring program 

developed in accordance with the guidance provided in NUMARC 93-01, Rev. 2 (Ref. 5) and 

RG 1.160, Rev. 2 (Ref. 6). The applicant may choose to expand the scope of its structures 

monitoring program to include these structure/aging effect combinations. Otherwise, the 

reviewer reviews and evaluates the applicant’s proposed program in accordance with the 

guidance in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR.)

3.5.3.2.2.2 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. Structures monitoring program 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). Documented evidence confirms that 

where the existing concrete had air content of 3% to 6% and water-to-cement ratio of 0.35-

0.45, subsequent inspection did not exhibit degradation related to freeze-thaw. Such 

inspections should be considered a part of the evaluation. The weathering index for the 
September 2005 3.5-13 NUREG-1800, Rev. 1

continental US is shown in ASTM C33-90, Fig. 1. The reviewer confirms that the applicant 

has satisfied the 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 these aging effects in inaccessible areas for plants located in 

moderate to severe weathering conditions are adequately managed.

2. The GALL Report recommends further evaluation of programs to manage cracking due to 

expansion and reaction with aggregate in below-grade inaccessible concrete areas of 

Groups 1-5 and 7-9 structures in below-grade inaccessible concrete areas of Groups 1-3, 5, 

and 7-9 structures. An aging management program is not necessary, if there is documented 

evidence that confirms the in-place concrete was constructed in accordance with the 

recommendations in ACI 201.2R-77. The reviewer confirms that the applicant has satisfied 

the 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 these aging effects in inaccessible areas for concrete that was not constructed 

in accordance with the recommendations of ACI 201.2R-77 are adequately managed.

3. The GALL Report recommends further evaluation of programs to manage cracks and 

distortion due to increased stress levels from settlement, and reduction of foundation 

strength, cracking, and differential settlement due to erosion of porous concrete 

subfoundations could occur in below-grade inaccessible concrete areas of Groups 1-3, 5, 

and 7-9 structures. The initial licensing basis for some plants included a program to monitor 

settlement. If no settlement was evident during the first decade or so, the staff may have 

given the applicant approval to discontinue the program. However, if a de-watering system 

is relied upon for control of settlement and erosion, then the applicant is to ensure proper 

functioning of the de-watering system through the period of extended operation. 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 aging management for inaccessible 

concrete areas, such as foundation and exterior walls below grade exposed to an 

aggressive environment. Possible aging effects are increases in porosity and permeability, 

cracking and loss of material (spalling, scaling) due to aggressive chemical attack, and 

cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded 

steel for Groups 1-3, 5, 7-9 structures. Periodic monitoring of below-grade water chemistry 

(including consideration of potential seasonal variations) is an acceptable approach to 

demonstrate that the below-grade environment is aggressive or non-aggressive. The GALL 

Report recommends that examination of representative samples of below-grade concrete, 

when excavated for any reason, be performed. 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.

5. The GALL Report recommends further evaluation of programs to manage increase in 

porosity and permeability due to leaching of calcium hydroxide in below-grade inaccessible 

concrete areas of Groups 1-3, 5, and 7-9 structures. An aging management program is not 

necessary, if there is documented evidence that confirms the in-place concrete was 
NUREG-1800, Rev. 1 3.5-14 September 2005

constructed in accordance with the recommendations in ACI 201.2R-77. The reviewer 

confirms that the applicant has satisfied the conditions for inaccessible concrete 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 these aging effects in inaccessible 

areas for concrete that was not constructed in accordance with the recommendations of ACI 

201.2R-77 are adequately managed.

3.5.3.2.2.3 Reduction of Strength and Modulus of Concrete Structures 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 reviewer reviews and confirms that the applicant’s discussion in the license renewal 

application indicates that the affected PWR and BWR safety-related and other structures are not 

exposed to temperature that exceeds the temperature limits. For concrete structural 

components in Groups 1-5 structures that operate above these temperature limits, the reviewer 

reviews the applicant’s proposed programs on a case-by-case basis to ensure that the effects of 

elevated temperature will be managed during the period of extended operation.

3.5.3.2.2.4 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 the FERC / 

US Army Corp of Engineers dam inspections and maintenance.

1. Increases in porosity and permeability, cracking and loss of material (spalling, scaling) due 

to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel could occur in below-grade inaccessible 

concrete areas of Group 6 structures. Periodic monitoring of below-grade water chemistry 

(including consideration of potential seasonal variations) is an acceptable approach to 

demonstrate that the below-grade environment is aggressive or non-aggressive. The GALL 

Report recommends that examination of representative samples of below-grade concrete, 

when excavated for any reason, be performed, if the below-grade environment is 

aggressive. The reviewer reviews the applicant’s proposed aging management program to 

determine that, where appropriate, an effective inspection program will be implemented to 

ensure that the aging effects in inaccessible areas are adequately managed during the 

period of extended operation.

2. 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). Documented evidence confirms that where the existing 

concrete had air content of 3% to 6% and water-to-cement ratio of 0.35-0.45, subsequent 
September 2005 3.5-15 NUREG-1800, Rev. 1

inspection did not exhibit degradation related to freeze-thaw. Such inspections should be 

considered a part of the evaluation. The weathering index for the continental US is shown in 

ASTM C33-90, Fig. 1. The reviewer reviews and confirms that the applicant has satisfied the 

conditions for inaccessible concrete 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 these aging effects in inaccessible areas for plants located in moderate to 

severe weathering conditions are adequately managed.

3. Cracking due to expansion and reaction with aggregate could occur in below-grade 

inaccessible concrete areas of Group 6 structures and increase in porosity and permeability 

due to leaching of calcium hydroxide could occur in below-grade inaccessible concrete 

areas of Group 6 structures. An aging management program is not necessary, even if 

reinforced concrete is exposed to flowing water, if there is documented evidence that 

confirms the in-place concrete was constructed in accordance with the recommendations in 

ACI 201.2R-77. The reviewer reviews and confirms that the applicant has satisfied the 

conditions for inaccessible concrete 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 these aging effects in inaccessible areas for concrete that was not constructed 

in accordance with the recommendations of ACI 201.2R-77 are adequately managed.

3.5.3.2.2.5 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.

3.5.3.2.2.6 Aging of Supports Not Covered by Structures Monitoring Program

The GALL Report recommends further evaluation of certain component support/aging effect 

combinations if they are not covered by the structures monitoring program. This includes 

(1) reduction in concrete anchor capacity due to degradation of the surrounding concrete, for 

Groups B1-B5 supports; (2) loss of material due to general and pitting corrosion, for Groups B2-

B5 supports; and (3) reduction/loss of isolation function due to degradation of vibration isolation 

elements, for Group B4 supports. Further evaluation is necessary only for structure/aging effect 

combinations not covered by the structures monitoring program. 

The aging management program consists of a structures monitoring program to verify that the 

CLB is maintained through periodic testing and inspection of critical plant structures, systems, 

and components. The reviewer confirms that the applicant has identified the component 

support/aging effect combinations not within the scope of the applicant’s structures monitoring 

program developed in accordance with the guidance provided in NUMARC 93-01, Rev. 2 

(Ref. 5) and RG 1.160, Rev. 2 (Ref. 6). The applicant may choose to expand the scope of its 

structures monitoring program to include these component support/aging effect combinations. 

Otherwise, the reviewer reviews and evaluates the applicant’s proposed program in accordance 

with the guidance in Branch Technical Position RLSB-1 (Appendix A.1 of this SRP-LR).
NUREG-1800, Rev. 1 3.5-16 September 2005

3.5.3.2.2.7 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 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 RLSB-1 (Appendix A.1 of this SRP-LR). 

3.5.3.4 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in 

Table 3.5-2 in the FSAR supplement for aging management of the containment, structures, and 

component Supports for license renewal. The reviewer also confirms that the applicant has 

provided information equivalent to that in Table 3.5-2 in the FSAR supplement for SRP-LR 

Subsection 3.5.3.3, “AMR Results Not Consistent with or Not Addressed in the GALL Report.”

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 3.5-2, 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.
September 2005 3.5-17 NUREG-1800, Rev. 1

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 

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

Power Plants,” U.S. Nuclear Regulatory Commission, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.

3. American Society of Mechanical Engineers, 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, 2001 edition including the 2002 and 2003 

Addenda. The ASME Boiler and Pressure Vessel Code, the American Society of Mechanical 

Engineers, New York, NY.

4. American Society of Mechanical Engineers, 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, 1992 edition 

with 2001 edition including the 2002 and 2003 Addenda. The ASME Boiler and Pressure 

Vessel Code, the American Society of Mechanical Engineers, New York, NY.

5. 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. 

6. NRC Regulatory Guide 1.160, Revision 2, “Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants,” March 1997.
NUREG-1800, Rev. 1 3.5-18 September 2005

7. NUREG-1557, October 1996, “Summary of Technical Information and Agreements from 

Nuclear Management and Resource Council Industry Report addressing License Renewal”.

8. ACI 201.2R 77 “Guide to Durable Concrete,” American Concrete Institute, Detroit, MI, 

Reapproved 1982.
September 2005 3.5-19 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

PWR Concrete (Reinforced and Prestressed) and Steel Containments 

BWR Concrete and Steel (Mark I, II, and III) Containments

1 BWR/ 

PWR

Concrete elements: walls, 

dome, basemat, ring girder, 

buttresses, containment (as 

applicable) 

Aging of accessible 

and inaccessible 

concrete areas due to 

aggressive chemical 

attack, and corrosion 

of embedded steel

ISI (IWL) and for inaccessible 

concrete, an examination of 

representative samples of belowgrade concrete, and periodic 

monitoring of groundwater, if the 

environment is non-aggressive. A 

plant specific program is to be 

evaluated if environment is 

aggressive.

Yes, plantspecific, if the 

environment is 

aggressive (See 

subsection 

3.5.2.2.1.1) 

C-03

C-05

C-25

C-26

C-27

C-41

C-42

C-43

2 BWR/ 

PWR

Concrete elements; All Cracks and distortion 

due to increased 

stress levels from 

settlement 

Structures Monitoring Program. 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 not within 

the scope of the 

applicant’s 

structures 

monitoring 

program or a dewatering system 

is relied upon 

(See subsection 

3.5.2.2.1.2) 

C-06

C-36

C-37

3 BWR/ 

PWR

Concrete elements: 

foundation, sub-foundation 

Reduction in 

foundation strength, 

cracking, differential 

settlement due to 

erosion of porous 

concrete 

Structures Monitoring Program

If a de-watering system is relied 

upon for control of erosion of cement 

from porous concrete 

subfoundations, then the licensee is 

to ensure proper functioning of the 

Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program or a deC-07
NUREG-1800, Rev. 1 3.5-20 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

subfoundation de-watering system through the 

period of extended operation.

watering system 

is relied upon 

(See subsection 

3.5.2.2.1.2) 

4 BWR/ 

PWR

Concrete elements: dome, 

wall, basemat, ring girder, 

buttresses, containment, 

concrete fill-in annulus (as 

applicable) 

Reduction of strength 

and modulus of 

concrete due to 

elevated temperature 

A plant-specific aging management 

program is to be evaluated

Yes, plantspecific if 

temperature 

limits are 

exceeded (See 

subsection 

3.5.2.2.1.3) 

C-08

C-33

C-34

C-35

C-50

5 BWR Steel elements: Drywell; 

torus; drywell head; 

embedded shell and sand 

pocket regions; drywell 

support skirt; torus ring 

girder; downcomers; liner 

plate, ECCS suction 

header, support skirt, 

region shielded by 

diaphragm floor, 

suppression chamber (as 

applicable)

Loss of material due 

to general, pitting and 

crevice corrosion 

ISI (IWE), and10 CFR Part 50, 

Appendix J. 

Yes, if corrosion

is significant for 

inaccessible 

areas (See 

subsection 

3.5.2.2.1.4) 

C-19

C-46

6 BWR/

PWR

Steel elements: steel liner, 

liner anchors, integral 

attachments

Loss of material due 

to general, pitting and 

crevice corrosion 

ISI (IWE), and 10 CFR Part 50, 

Appendix J. 

Yes, if corrosion 

is significant for 

inaccessible 

areas (See 

subsection 

3.5.2.2.1.4) 

C-09
September 2005 3.5-21 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

7 BWR/ 

PWR

Prestressed containment 

tendons 

Loss of prestress due 

to relaxation, 

shrinkage, creep, and 

elevated temperature 

TLAA, evaluated in accordance with 

10 CFR 54.21(c) 

Yes, TLAA (See 

subsection 

3.5.2.2.1.5) 

C-11

8 BWR Steel and stainless steel 

elements: vent line, vent 

header, vent line bellows; 

downcomers; 

Cumulative fatigue 

damage (CLB fatigue 

analysis exists) 

TLAA, evaluated in accordance with

10 CFR 54.21(c) 

Yes, TLAA (See 

subsection 

3.5.2.2.1.6) 

C-21 

C-48

9 BWR/ 

PWR

Steel, stainless steel 

elements, dissimilar metal 

welds: 

penetration sleeves, 

penetration bellows; 

suppression pool shell, 

unbraced downcomers

Cumulative fatigue 

damage (CLB fatigue 

analysis exists) 

TLAA, evaluated in accordance with 

10 CFR 54.21(c) 

Yes, TLAA (See 

subsection 

3.5.2.2.1.6) 

C-13

C-45

10 BWR/ 

PWR

Stainless steel penetration 

sleeves, penetration 

bellows, dissimilar metal 

welds

Cracking due to 

stress corrosion 

cracking

ISI (IWE) and 10 CFR Part 50, 

Appendix J, and additional 

appropriate 

examinations/evaluations for bellows 

assemblies and dissimilar metal 

welds.

Yes, detection of 

aging effects is to 

be evaluated 

(See subsection 

3.5.2.2.1.7) 

C-15

11 BWR Stainless steel vent line 

bellows, 

Cracking due to 

stress corrosion 

cracking

ISI (IWE) and 10 CFR Part 50, 

Appendix J, and additional 

appropriate examination/evaluation 

for bellows assemblies and dissimilar 

metal welds.

Yes, detection of 

aging effects is to 

be evaluated 

(See subsection 

3.5.2.2.1.7) 

C-22
NUREG-1800, Rev. 1 3.5-22 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

12 BWR/ 

PWR

Steel, stainless steel 

elements, dissimilar metal 

welds: 

penetration sleeves, 

penetration bellows; 

suppression pool shell, 

unbraced downcomers 

Cracking due to 

cyclic loading

ISI (IWE) and 10 CFR Part 50, 

Appendix J, and supplemented to 

detect fine cracks

Yes, detection of 

aging effects is to 

be evaluated 

(See subsection 

3.5.2.2.1.8) 

C-14

C-44

13 BWR Steel, stainless steel 

elements, dissimilar metal 

welds: torus; vent line; vent 

header; vent line bellows; 

downcomers 

Cracking due to 

cyclic loading

ISI (IWE) and 10 CFR Part 50, 

Appendix J, and supplemented to 

detect fine cracks

Yes, detection of 

aging effects is to 

be evaluated 

(See subsection 

3.5.2.2.1.8) 

C-20 

C-47

14 BWR/ 

PWR

Concrete elements: dome, 

wall, basemat ring girder, 

buttresses, containment (as 

applicable) 

Loss of material 

(Scaling, cracking, 

and spalling) due to 

freeze-thaw

ISI (IWL). Evaluation is needed for 

plants that are located in moderate 

to severe weathering conditions 

(weathering index >100 day-inch/yr) 

(NUREG-1557).

Yes, for 

inaccessible 

areas of plants 

located in 

moderate to 

severe 

weathering 

conditions (See 

subsection 

3.5.2.2.1.9) 

C-01

C-28

C-29
September 2005 3.5-23 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

15 BWR/ 

PWR

Concrete elements: walls, 

dome, basemat, ring girder, 

buttresses, containment, 

concrete fill-in annulus (as 

applicable). 

Cracking due to 

expansion and 

reaction with 

aggregate; increase 

in porosity, 

permeability due to 

leaching of calcium 

hydroxide 

ISI (IWL) for accessible areas. None 

for inaccessible areas if concrete 

was constructed in accordance with 

the recommendations in ACI 201.2R.

Yes, if concrete 

was not 

constructed as 

stated for 

inaccessible 

areas (See 

subsection 

3.5.2.2.1.10)

C-02

C-04

C-30

C-31

C-32

C-38

C-39

C-40

C-51

16 BWR/ 

PWR

Seals, gaskets, and 

moisture barriers 

Loss of sealing and 

leakage through 

containment due to 

deterioration of joint 

seals, gaskets, and 

moisture barriers 

(caulking, flashing, 

and other sealants)

ISI (IWE) and 10 CFR Part 50, 

Appendix J 

No C-18

17 BWR/ 

PWR

Personnel airlock, 

equipment hatch and CRD 

hatch locks, hinges, and 

closure mechanisms

Loss of leak tightness 

in closed position due 

to mechanical wear 

of locks, hinges and 

closure mechanisms

10 CFR Part 50, Appendix J and 

Plant Technical Specifications 

No C-17

18 BWR/ 

PWR

Steel penetration sleeves 

and dissimilar metal welds; 

personnel airlock, 

equipment hatch and CRD 

hatch

Loss of material due 

to general, pitting, 

and crevice corrosion

ISI (IWE) and 10 CFR Part 50, 

Appendix J. 

No C-12

C-16
NUREG-1800, Rev. 1 3.5-24 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

19 BWR Steel elements: stainless 

steel suppression chamber 

shell (inner surface)

Cracking due to 

stress corrosion 

cracking

ISI (IWE) and 10 CFR Part 50, 

Appendix J 

No C-24

20 BWR Steel elements: 

suppression chamber liner 

(interior surface)

Loss of material due 

to general, pitting, 

and crevice corrosion

ISI (IWE) and 10 CFR Part 50, 

Appendix J 

No C-49

21 BWR Steel elements: drywell 

head and downcomer pipes 

Fretting or lock up 

due to mechanical 

wear 

ISI (IWE) No C-23

22 BWR/ 

PWR

Prestressed containment: 

tendons and anchorage 

components

Loss of material due 

to corrosion

ISI (IWL) No C-10

Safety-Related and Other Structures; and Component Supports

23 BWR/ 

PWR

All Groups except Group 6: 

interior and above grade 

exterior concrete

Cracking, loss of 

bond, and loss of 

material (spalling,

scaling) due to 

corrosion of 

embedded steel

Structures Monitoring Program Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1) 

T-04

24 BWR/ 

PWR

All Groups except Group 6: 

interior and above grade 

exterior concrete

Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling) due to 

Structures Monitoring Program Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

T-06
September 2005 3.5-25 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

aggressive chemical 

attack

program (See 

subsection 

3.5.2.2.2.1) 

25 BWR/ 

PWR

All Groups except Group 6: 

steel components: all 

structural steel 

Loss of material due 

to corrosion

Structures Monitoring Program. If 

protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address 

protective coating monitoring and 

maintenance.

Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1) 

T-11

26 BWR/ 

PWR

All Groups except Group 6: 

accessible and inaccessible 

concrete: foundation

Loss of material 

(spalling, scaling) and 

cracking due to 

freeze-thaw

Structures Monitoring Program. 

Evaluation is needed for plants that 

are located in moderate to severe 

weathering conditions (weathering 

index >100 day-inch/yr) (NUREG1557).

Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1) or for 

inaccessible 

areas of plants 

located in 

moderate to 

severe 

weathering 

conditions (See 

subsection 

3.5.2.2.2.2.1) 

T-01

27 BWR/ 

PWR

All Groups except Group 6: 

accessible and inaccessible 

interior/exterior concrete 

Cracking due to 

expansion due to 

reaction with 

Structures Monitoring Program.

None for inaccessible areas if 

concrete was constructed in 

Yes, if not within 

the scope of the 

applicant’s 

T-03
NUREG-1800, Rev. 1 3.5-26 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

aggregates accordance with the 

recommendations in ACI 201.2R-77.

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1) or 

concrete was not 

constructed as 

stated for 

inaccessible 

areas (See 

subsection 

3.5.2.2.2.2.2) 

28 BWR/ 

PWR

Groups 1-3, 5-9: All Cracks and distortion 

due to increased 

stress levels from 

settlement 

Structures Monitoring Program. 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 not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1) or a 

de-watering 

system is relied 

upon (See 

subsection 

3.5.2.2.2.2.3) 

T-08

29 BWR/ 

PWR

Groups 1-3, 5-9: foundation Reduction in 

foundation strength, 

cracking, differential 

settlement due to 

erosion of porous 

concrete 

Structures Monitoring Program. 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 

Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

T-09
September 2005 3.5-27 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

subfoundation extended operation. subsection 

3.5.2.2.2.1) or a 

de-watering 

system is relied 

upon (See 

subsection 

3.5.2.2.2.2.3) 

30 BWR/ 

PWR

Group 4: Radial beam 

seats in BWR drywell; RPV 

support shoes for PWR with 

nozzle supports; Steam 

generator supports 

Lock-up due to wear ISI (IWF) or Structures monitoring 

Program

Yes, if not within 

the scope of ISI 

or structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.1)

T-13

31 BWR/ 

PWR

Groups 1-3, 5, 7-9: belowgrade concrete 

components, such as 

exterior walls below grade 

and foundation 

Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling)/ aggressive 

chemical attack;

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ corrosion of 

embedded steel

Structures Monitoring Program; 

Examination of representative 

samples of below-grade concrete, 

and periodic monitoring of 

groundwater, if the environment is 

non-aggressive. A plant specific 

program is to be evaluated if 

environment is aggressive.

Yes, plantspecific, if 

environment is 

aggressive (See 

subsection 

3.5.2.2.2.2.4) 

T-05

T-07

32 BWR/ 

PWR

Groups 1-3, 5, 7-9: exterior 

above and below grade 

reinforced concrete 

foundations

Increase in porosity 

and permeability, and 

loss of strength due 

to leaching of calcium 

hydroxide 

Structures monitoring Program for 

accessible areas. None for 

inaccessible areas if concrete was 

constructed in accordance with the 

recommendations in ACI 201.2R-77.

Yes, if concrete 

was not 

constructed as 

stated for 

inaccessible 

areas (See 

T-02
NUREG-1800, Rev. 1 3.5-28 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

subsection 

3.5.2.2.2.2.5)

33 BWR/ 

PWR

Groups 1-5: concrete Reduction of strength 

and modulus of

concrete due to 

elevated temperature 

A plant-specific aging management 

program is to be evaluated 

Yes, plantspecific if 

temperature 

limits are 

exceeded (See 

subsection 

3.5.2.2.2.3) 

T-10

34 BWR/ 

PWR

Group 6: 

Concrete;

all

 Increase in porosity 

and permeability, 

cracking, loss of 

material due to 

aggressive chemical 

attack; cracking, loss 

of bond, loss of 

material due to 

corrosion of 

embedded steel 

Inspection of Water-Control 

Structures or FERC/US Army Corps 

of Engineers dam inspections and 

maintenance programs and for 

inaccessible concrete, an 

examination of representative 

samples of below-grade concrete, 

and periodic monitoring of 

groundwater, if the environment is 

non-aggressive. A plant specific 

program is to be evaluated if 

environment is aggressive.

Yes, plantspecific if 

environment is 

aggressive (See 

subsection 

3.5.2.2.2.4.1) 

T-18

T-19

35 BWR/ 

PWR

Group 6: exterior above 

and below grade concrete 

foundation 

Loss of material 

(spalling, scaling) and 

cracking due to 

freeze-thaw

Inspection of Water-Control 

Structures or FERC/US Army Corps 

of Engineers dam inspections and 

maintenance programs. Evaluation is 

needed for plants that are located in 

moderate to severe weathering 

conditions (weathering index >100 

day-inch/yr) (NUREG-1557).

Yes, for 

inaccessible 

areas of plants 

located in 

moderate to 

severe 

weathering 

conditions (See 

subsection 

3.5.2.2.2.4.2)

T-15
September 2005 3.5-29 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

36 BWR/ 

PWR

Group 6: all accessible/ 

inaccessible reinforced 

concrete

Cracking due to 

expansion/ reaction 

with aggregates

Accessible areas: Inspection of 

Water-Control Structures or 

FERC/US Army Corps of Engineers 

dam inspections and maintenance 

programs. 

None for inaccessible areas if 

concrete was constructed in 

accordance with the 

recommendations in ACI 201.2R-77.

 Yes, if concrete 

was not 

constructed as 

stated for 

inaccessible 

areas (See 

subsection 

3.5.2.2.2.4.3)

T-17

37 BWR/ 

PWR

Group 6: exterior above 

and below grade reinforced 

concrete foundation interior 

slab 

Increase in porosity 

and permeability, loss 

of strength due to 

leaching of calcium 

hydroxide

For accessible areas, inspection of 

Water-Control Structures or 

FERC/US Army Corps of Engineers 

dam inspections and maintenance 

programs. None for inaccessible 

areas if concrete was constructed in 

accordance with the 

recommendations in ACI 201.2R-77.

 Yes, if concrete 

was not 

constructed as 

stated for 

inaccessible 

areas (See 

subsection 

3.5.2.2.2.4.3)

T-16

38 BWR/ 

PWR

Groups 7, 8: Tank liners Cracking due to 

stress corrosion 

cracking; loss of 

material due to pitting 

and crevice corrosion

A plant-specific aging management 

program is to be evaluated

Yes, plant 

specific (See 

subsection 

3.5.2.2.2.5)

T-23

39 BWR/ 

PWR

Support members; welds; 

bolted connections; support 

anchorage to building 

structure

Loss of material due 

to general and pitting 

corrosion

Structures Monitoring Program Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.6) 

T-30
NUREG-1800, Rev. 1 3.5-30 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

40 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

Structures Monitoring Program Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

Subsection 

3.5.2.2.2.6) 

T-29

41 BWR/ 

PWR

Vibration isolation elements Reduction or loss of 

isolation function/ 

radiation hardening, 

temperature, 

humidity, sustained 

vibratory loading

Structures Monitoring Program Yes, if not within 

the scope of the 

applicant’s 

structures 

monitoring 

program (See 

subsection 

3.5.2.2.2.6) 

T-31

42 BWR/ 

PWR

Groups B1.1, B1.2, and 

B1.3: support members: 

anchor bolts, welds

Cumulative fatigue 

damage (CLB fatigue 

analysis exists) 

TLAA, evaluated in accordance with 

10 CFR 54.21(c) 

Yes, TLAA (See 

subsection 

3.5.2.2.2.7) 

T-26

43 BWR/ 

PWR

Groups 1-3, 5, 6: all 

masonry block walls 

Cracking due to 

restraint shrinkage, 

creep, and 

aggressive 

environment 

Masonry Wall Program No T-12

44 BWR/ 

PWR

Group 6 elastomer seals, 

gaskets, and moisture 

barriers 

Loss of sealing due 

to deterioration of 

seals, gaskets, and 

moisture barriers 

(caulking, flashing, 

and other sealants) 

Structures Monitoring Program No TP-7
September 2005 3.5-31 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

45 BWR/ 

PWR

Group 6: exterior above 

and below grade concrete 

foundation; interior slab

Loss of material due 

to abrasion, 

cavitation

Inspection of Water-Control 

Structures or FERC/US Army Corps 

of Engineers dam inspections and 

maintenance 

No T-20

46 BWR/ 

PWR

Group 5: Fuel pool liners Cracking due to 

stress corrosion 

cracking; loss of 

material due to pitting 

and crevice corrosion

Water Chemistry and monitoring of 

spent fuel pool water level in 

accordance with technical 

specifications and leakage from the 

leak chase channels. 

No T-14

47 BWR/ 

PWR

Group 6: all metal structural 

members 

Loss of material due 

to general (steel 

only), pitting and 

crevice corrosion

Inspection of Water-Control 

Structures or FERC/US Army Corps 

of Engineers dam inspections and 

maintenance. If protective coatings 

are relied upon to manage aging, 

protective coating monitoring and 

maintenance provisions should be 

included. 

No T-21

48 BWR/ 

PWR

Group 6: 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

Inspection of Water-Control 

Structures or FERC/US Army Corps 

of Engineers dam inspections and 

maintenance programs 

No T-22

49 BWR Support members; welds; 

bolted connections; support 

anchorage to building 

structure

Loss of material/ 

general, pitting, and 

crevice corrosion

Water Chemistry and ISI(IWF) No TP-10

50 BWR/ 

PWR

Groups B2, and B4: 

galvanized steel, aluminum, 

Loss of material due 

to pitting and crevice 

Structures Monitoring Program No TP-6
NUREG-1800, Rev. 1 3.5-32 September 2005

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

stainless steel support 

members; welds; bolted 

connections; support 

anchorage to building 

structure

corrosion

51 BWR/ 

PWR

Group B1.1: high strength 

low-alloy bolts 

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general corrosion

Bolting Integrity No T-27

TP-9

52 BWR/ 

PWR

Groups B2, and B4: sliding 

support bearings and 

sliding support surfaces

Loss of mechanical 

function due to 

corrosion, distortion, 

dirt, overload, fatigue 

due to vibratory and 

cyclic thermal loads 

Structures Monitoring Program No TP-1

TP-2

53 BWR/ 

PWR

Groups B1.1, B1.2, and 

B1.3: support members: 

welds; bolted connections; 

support anchorage to 

building structure

Loss of material due 

to general and pitting 

corrosion

ISI (IWF) No T-24

54 BWR/ 

PWR

Groups B1.1, B1.2, and 

B1.3: 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

ISI (IWF) No T-28

55 PWR Steel, galvanized steel, and 

aluminum support 

members; welds; bolted 

Loss of material due 

to boric acid 

corrosion 

Boric Acid Corrosion No T-25

TP-3
September 2005 3.5-33 NUREG-1800, Rev. 1

Table 3.5-1. Summary of Aging Management Programs for Structures and Component Supports Evaluated in Chapters II and III of 

the GALL Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

connections; support 

anchorage to building 

structure

56 BWR/ 

PWR

Groups B1.1, B1.2, and 

B1.3: Sliding surfaces

Loss of mechanical

function due to 

corrosion, distortion, 

dirt, overload, fatigue 

due to vibratory and 

cyclic thermal loads

ISI (IWF) No T-32

57 BWR/ 

PWR

Groups B1.1, B1.2, and 

B1.3: Vibration isolation 

elements

Reduction or loss of 

isolation function/ 

radiation hardening,

temperature, 

humidity, sustained 

vibratory loading

ISI (IWF) No T-33

58 BWR/ 

PWR

Galvanized steel and 

aluminum support 

members; welds; bolted 

connections; support 

anchorage to building 

structure exposed to air -

indoor uncontrolled

None None NA - No AEM or 

AMP

TP-8

TP-11

59 BWR/ 

PWR

Stainless steel support 

members; welds; bolted 

connections; support 

anchorage to building 

structure

None None NA - No AEM or 

AMP

TP-4

TP-5
NUREG-1800, Rev. 1 3.5-34 September 2005

Table 3.5-2. FSAR Supplement for Aging Management of Structures and 

Component Supports

Program Description of Program

Implementation 

Schedule*

Inservice Inspection 

(IWL) 

The ASME Section XI, Subsection IWL program 

consists of periodic visual inspection of 

concrete surfaces for reinforced and 

prestressed concrete containments, and 

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. 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, 2001 edition including the 

2002 and 2003 Addenda. 

Existing program

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. This program is 

in accordance with ASME Section XI, 

Subsection IWE, 2001 edition including the 

2002 and 2003 Addenda.

Existing program

10 CFR Part 50, 

Appendix J

This program consists of monitoring of leakage 

rates through containment liner/welds, 

penetrations, fittings, and other access 

openings for detecting degradation of 

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

Protective Coating 

Monitoring and 

Maintenance 

Program

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. 0 or Rev. 1.

Existing program

Inspection of Watercontrol StructuresThe program consists of inspection and 

surveillance program 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.

Existing program
September 2005 3.5-35 NUREG-1800, Rev. 1

Table 3.5-2. FSAR Supplement for Aging Management of Structures and 

Component Supports

Program Description of Program

Implementation 

Schedule*

Monitoring of leakage 

in fuel storage facility 

This activity consists of periodic monitoring of 

leak chase system drain lines and leak 

detection sump of fuel storage facility and 

refueling channel to detect SCC and crevice 

corrosion of stainless steel liners. Alternately, 

the pool water level may be monitored for 

evidence of leakage. This activity augments the 

Water Chemistry Program for aging 

management of the spent fuel pool liner.

Existing program

Water Chemistry To mitigate aging effects on component 

surfaces that are exposed to water as process 

fluid, chemistry programs are used to control 

water impurities (e.g., chloride, fluoride, and 

sulfate) that accelerate corrosion. The water 

chemistry program relies on monitoring and 

control of water chemistry based on EPRI 

guidelines of TR -103515 for water chemistry in 

BWRs and TR-102134 for secondary water 

chemistry in PWRs.

Existing program

Masonry Wall This program consists of inspections, based on 

IE Bulletin 80-11 and plant-specific monitoring 

proposed by IN 87-67, for managing cracking of 

masonry walls.

Existing program

Inservice inspection

(IWF) 

This program consists of periodic visual 

examination of component supports for signs of 

degradation, evaluation, and corrective actions. 

This program is in accordance with ASME 

Section XI, Subsection IWF, 2001 edition 

including the 2002 and 2003 Addenda.

Existing program

Boric Acid Corrosion The program consists of (1) visual inspection of 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of 

leak path and removal of the boric acid 

residues, (3) assessment of the damage, and 

(4) follow-up inspection for adequacy. This 

program is implemented in response to 

GL 88-05.

Existing program
Draft NUREG-1800, Rev. 1 3.5-36 September 2005

Table 3.5-2. FSAR Supplement for Aging Management of Structures and 

Component Supports

Program Description of Program

Implementation 

Schedule*

Bolting Integrity This program consists of guidelines on 

materials selection, strength and hardness 

properties, installation procedures, lubricants,

and sealants, corrosion considerations in the 

selection and installation of pressure-retaining 

bolting for nuclear applications, and enhanced 

inspection techniques. This program relies on 

the bolting integrity program delineated in 

NUREG-1339 and industry’s recommendations 

delineated in EPRI NP-5769, with the 

exceptions noted in NUREG-1339 for safetyrelated bolting and in EPRI TR -104213 for 

pressure retaining bolting and structural bolting.

Existing program

Structures Monitoring The program consists of periodic inspection and 

monitoring the condition of structures and 

structure 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.

Existing program

Plant-specific The description should contain information 

associated with the basis for determining that 

aging effects will be managed during the period 

of extended operation.

Program should be 

implemented before 

the period of 

extended operation.

Quality Assurance The 10 CFR Part 50 App. B program provides 

for corrective actions, confirmation process, and 

administrative controls for aging management 

programs for license renewal. The scope of this 

existing program will be expanded to include 

nonsafety-related structures and components 

that are subject to an AMR for license renewal.

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.
September 2005 3.6-1 NUREG-1800, Rev. 1

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 aging management review (AMR) and the associated aging 

management program (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 plantspecific 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 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.

3.6.2 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 (GALL Report).

The applicant’s LRA should provide sufficient information so that the NRC reviewer is able to 

confirm that the specific LRA AMR line-item and the associated LRA AMP are consistent with 

the cited GALL Report AMR line-item. The staff reviewer should then confirm that the LRA AMR 

line-item is consistent with the GALL Report AMR line-item to which it is compared. 
NUREG-1800, Rev. 1 3.6-2 September 2005

For AMPs, 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 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 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.

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 apply to all of the AMRs and AMPs 

reviewed as part of this section. In addition, if the GALL Report AMR line-item to which the LRA 

AMR line-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.

3.6.2.2.1 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 Degradation of Insulator Quality due to Presence of Any Salt Deposits and 

Surface Contamination, and Loss of Material due to Mechanical Wear

Degradation of insulator quality 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 aging management program 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 aging management program 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 and Fatigue, 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 and fatigue, loss of conductor strength due to 

corrosion, and increased resistance of connection due to oxidation or loss of pre-load could 
September 2005 3.6-3 NUREG-1800, Rev. 1

occur in transmission conductors and connections, and in switchyard bus and connections. The 

GALL Report recommends further evaluation of a plant-specific aging management program 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).

3.6.2.2.4 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 

standard review plan).

3.6.2.4 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. Examples of the type of information required are provided in 

Table 3.6-2 of this SRP-LR.

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 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 electrical and 

I&C components that are contained in GALL as applicable to its plant. 

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 AMP, then the reviewer is to confirm that this enhancement when 
NUREG-1800, Rev. 1 3.6-4 September 2005

implemented will indeed make the LRA AMP consistent with the GALL AMP. If the applicant 

identifies, in the LRA AMP, an exception to any of the program elements of the GALL AMP with

which the applicant is claiming to be consistent, 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 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 GALL pertinent to the 

electrical and I&C components are summarized in Table 3.6-1 of this SRP-LR. In this table, the 

ID column provides a row identifier useful in matching the information presented in the 

corresponding table in the GALL Report Vol. 1. The related item column identifies the item 

number in the GALL Report Vol. 2, Chapters II through VIII, presenting detailed information 

summarized by this row.

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 apply to all of the AMRs and AMPs 

provided in this section. In addition, if the GALL AMR line-item to which the LRA AMR line-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 Degradation of Insulator Quality due to Presence of Any Salt Deposits and 

Surface Contamination, and Loss of Material due to Mechanical Wear

The GALL Report recommends a plant-specific aging management program for the 

management of degradation of insulator quality 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.

3.6.3.2.3 Loss of Material due to Wind Induced Abrasion and Fatigue, Loss of Conductor 

Strength due to Corrosion, and Increased Resistance of Connection due to 

Oxidation or Loss of Pre-load

The GALL Report recommends a plant-specific aging management program for the 

management of loss of material due to wind induced abrasion and fatigue, loss of conductor 

strength due to corrosion, and increased resistance of connection due to oxidation or loss of 

pre-load in 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.
September 2005 3.6-5 NUREG-1800, Rev. 1

3.6.3.2.4 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 non safety-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 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 

aging management programs that will adequately manage the aging effects. The aging 

management program credited 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).

3.6.3.4 FSAR Supplement

The reviewer confirms that the applicant has provided information equivalent to that in Table 

3.6-2 in the FSAR supplement for aging management of the Electrical and I&C System for 

license renewal. The reviewer also confirms that the applicant has provided information 

equivalent to that in Table 3.6-2 in the FSAR supplement for Section 3.6.3.3, “AMR Results Not 

Consistent with or Not Addressed in the GALL Report.” 

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 3.6-2, 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:
NUREG-1800, Rev. 1 3.6-6 September 2005

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.

3.6.6 References

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

Power Plants,” U.S. Nuclear Regulatory Commission, July 1981.

2. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.
September 2005 3.6-7 NUREG-1800, Rev. 1

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL 

Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

1 BWR/ 

PWR

Electrical equipment subject 

to 10 CFR 50.49 

environmental qualification 

(EQ) requirements

Degradation due to 

various aging 

mechanisms 

Environmental Qualification Of 

Electric Components 

Yes, TLAA (See 

subsection 

3.6.2.2.1) 

L-05

2 BWR/ 

PWR

Electrical cables, 

connections and fuse 

holders (insulation) not 

subject to 10 CFR 50.49 EQ 

requirements 

Reduced insulation 

resistance and 

electrical failure due 

to various physical, 

thermal, radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables and Connections 

Not Subject To 10 CFR 50.49 EQ 

Requirements 

No L-01

LP-03

3 BWR/ 

PWR

Conductor insulation for 

electrical cables and 

connections used in 

instrumentation circuits not 

subject to 10 CFR 50.49 EQ 

requirements that are 

sensitive to reduction in 

conductor insulation 

resistance (IR) 

Reduced insulation 

resistance and 

electrical failure due 

to various physical, 

thermal, radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables And Connections 

Used In Instrumentation Circuits Not 

Subject To 10 CFR 50.49 EQ 

Requirements 

No L-02

4 BWR/ 

PWR

Conductor insulation for 

inaccessible medium 

voltage (2 kV to 35 kV) 

cables (e.g., installed in 

conduit or direct buried) not 

subject to 10 CFR 50.49 EQ 

requirements 

Localized damage 

and breakdown of 

insulation leading to 

electrical failure due 

to moisture intrusion, 

water trees 

Inaccessible Medium Voltage 

Cables Not Subject To 10 CFR 

50.49 EQ Requirements 

No L-03
NUREG-1800, Rev. 1 3.6-8 September 2005

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL 

Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

5 PWR Connector contacts for 

electrical connectors 

exposed to borated water 

leakage

Corrosion of 

connector contact 

surfaces due to 

intrusion of borated 

water 

Boric Acid Corrosion No L-04

6 BWR/ 

PWR

Fuse Holders (Not Part of a 

Larger Assembly): Fuse 

holders – metallic clamp 

Fatigue due to ohmic 

heating, thermal 

cycling, electrical 

transients, frequent 

manipulation, 

vibration, chemical 

contamination, 

corrosion, and 

oxidation 

Fuse Holders No LP-01

7 BWR/ 

PWR

Metal enclosed bus -

Bus/connections 

Loosening of bolted 

connections due to 

thermal cycling and

ohmic heating 

Metal Enclosed Bus No LP-04

8 BWR/ 

PWR

Metal enclosed bus –

Insulation/insulators 

Reduced insulation 

resistance and 

electrical failure due 

to various physical, 

thermal, radiolytic, 

photolytic, and 

chemical 

mechanisms

Metal Enclosed Bus No LP-05

9 BWR/ 

PWR

Metal enclosed bus –

Enclosure assemblies 

Loss of material due 

to general corrosion 

Structures Monitoring Program No LP-06
September 2005 3.6-9 NUREG-1800, Rev. 1

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL 

Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

10 BWR/ 

PWR

Metal enclosed bus –

Enclosure assemblies 

Hardening and loss 

of strength due to 

elastomers 

degradation 

Structures Monitoring Program No LP-10

11 BWR/ 

PWR

High voltage insulators Degradation of 

insulation quality due 

to presence of any 

salt deposits and 

surface 

contamination, Loss 

of material caused by 

mechanical wear due 

to wind blowing on 

transmission 

conductors 

A plant-specific aging management 

program is to be evaluated.

Yes, plant 

specific (See 

subsection 

3.6.2.2.2) 

LP-07

LP-11

12 BWR/ 

PWR

Transmission conductors 

and connections,

Switchyard bus and 

connections 

Loss of material due 

to wind induced 

abrasion and fatigue,

Loss of conductor 

strength due to 

corrosion, Increased 

resistance of 

connection due to 

oxidation or loss of 

preload

A plant-specific aging management 

program is to be evaluated. 

Yes, plant 

specific (see 

subsection 

3.6.2.2.3) 

LP-08

LP-09
NUREG-1800, Rev. 1 3.6-10 September 2005

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the GALL 

Report

ID Type Component Aging 

Effect/Mechanism Aging Management Programs

Further 

Evaluation 

Recommended

Related 

Item

13 BWR/ 

PWR

Cable Connections –

Metallic parts 

Loosening of bolted 

connections due to 

thermal cycling, 

ohmic heating, 

electrical transients, 

vibration, chemical 

contamination, 

corrosion, and 

oxidation 

Electrical Cable Connections Not 

Subject To 10 CFR 50.49 

Environmental Qualification 

Requirements 

No LP-12

14 BWR/ 

PWR

Fuse Holders (Not Part of a 

Larger Assembly) Insulation 

material 

None None NA - No AEM or 

AMP

LP-02
September 2005 3.6-11 NUREG-1800, Rev. 1

Table 3.6-2. FSAR Supplement for Aging Management of Electrical and 

Instrumentation and Control System

Program Description of Program

Implementation 

Schedule*

Non-Environmentally 

Qualified Electrical 

Cables and 

Connections exposed 

to an adverse localized 

environment caused by 

heat, radiation, or 

moisture.

Accessible electrical cables and connections 

installed in adverse localized environments are 

visually inspected at least once every 10 years 

for cable and connection jacket surface 

anomalies, such as embrittlement, discoloration, 

cracking, swelling, or surface contamination, 

which are precursor indications of conductor 

insulation aging degradation from heat, radiation 

or moisture. An adverse localized environment is 

a condition in a limited plant area that is 

significantly more severe than the specified 

service condition for the electrical cable or 

connection.

First inspection for 

license renewal should 

be completed before 

the period of extended 

operation.

Non-Environmentally 

Qualified Electrical 

Cables and 

Connections used in 

instrumentation circuits 

that are sensitive to 

reduction in conductor 

insulation resistance, 

and are exposed to an 

adverse localized 

environment caused by 

heat, radiation, or 

moisture.

Electrical cables and connections used in circuits 

with sensitive, low-level signals, such as radiation 

monitoring and nuclear instrumentation, are 

calibrated as part of the instrumentation loop 

calibration at the normal calibration frequency, 

which provides sufficient indication of the need 

for corrective actions based on acceptance 

criteria related to instrumentation loop 

performance. The review of calibration results is 

performed once every 10 years.

In cases where cables are not part of calibration 

or surveillance program, a proven cable test 

(such as insulation resistance tests, time domain 

reflectometry tests, or other tests judged to be 

effective) for detecting deterioration of the 

insulation system are performed. The test 

frequency is based on engineering evaluation not 

to exceed 10 years.

First review of 

calibration results or 

cable tests for license 

renewal should be 

completed before the 

period of extended 

operation.
NUREG-1800, Rev. 1 3.6-12 September 2005

Table 3.6-2. FSAR Supplement for Aging Management of Electrical and 

Instrumentation and Control System

Program Description of Program

Implementation 

Schedule*

Non-Environmentally 

Qualified Inaccessible 

Medium-Voltage 

Cables exposed to an 

adverse localized 

environment caused by 

moisture and voltage 

exposure

In-scope, medium-voltage cables exposed to 

significant moisture and significant voltage are 

tested at least once every 10 years to provide an 

indication of the condition of the conductor 

insulation. The specific type of test performed will 

be determined prior to the initial test, and is to be 

a proven test for detecting deterioration of the 

insulation system due to wetting, such as power 

factor, partial discharge, or polarization index, as 

described in EPRI TR -103834-P1-2, or other 

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

is performed. Significant moisture is defined as 

periodic exposures that last more than a few 

days (e.g., cable in standing water). Periodic 

exposures that last less than a few days (e.g., 

normal rain and drain) are not significant. 

Significant voltage exposure is defined as being 

subjected to system voltage for more than 25% of 

the time. The moisture and voltage exposures 

described as significant in these definitions are 

not significant for medium-voltage cables that are 

designed for these conditions (e.g., continuous 

wetting and continuous energization are not 

significant for submarine cables). In addition, 

inspection for water collection is performed based 

on actual plant experience with water 

accumulation in the manholes. However, the 

inspection frequency should be at least once 

every two years. 

First tests or first 

inspections for license 

renewal should be 

completed before the 

period of extended 

operation.

Boric Acid Corrosion The program consists of (1) visual inspection of 

external surfaces that are potentially exposed to 

borated water leakage, (2) timely discovery of 

leak path and removal of the boric acid residues, 

(3) assessment of the damage, and (4) follow-up 

inspection for adequacy. This program is 

implemented in response to GL 88-05. 

Existing program.

Plant-specific AMP The description should contain information 

associated with the basis for determining that 

aging effects will be managed during the period 

of extended operation.

Program should be 

implemented before 

the period of extended 

operation.

Fuse Holders Fuse holders within the scope of license renewal 

will be tested at least once every 10 years to 

provide an indication of degradation 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 should be 

completed before the 

period of extended 

operation.
September 2005 3.6-13 NUREG-1800, Rev. 1

Table 3.6-2. FSAR Supplement for Aging Management of Electrical and 

Instrumentation and Control System

Program Description of Program

Implementation 

Schedule*

Metal Enclosed Bus Internal portions of MEBs are visually inspected 

for cracks, corrosion, foreign debris, excessive 

dust buildup, and evidence of moisture intrusion. 

The bus insulation is inspected for signs of 

embrittlement, cracking, melting, swelling, or 

discoloration, which may indicate overheating or 

aging degradation. The (internal) bus supports 

are inspected for structural integrity and signs of 

cracks. A sample of accessible bolted 

connections on the internal bus work is checked 

for loose connection by using thermography, or 

by measuring connection resistance using a low 

range ohmmeter. These inspections are 

performed at least once every 10 years.

As an alternative to thermography or measuring 

connection resistance of bolted connections, 

those bolted connections covered with heat 

shrink tape, sleeving, insulating boots, etc., may 

use visual inspection of insulation material to 

detect surface anomalies, such as discoloration, 

cracking, chipping or surface contamination. 

When this alternative visual inspection is used to 

check bolted connections, the inspections are 

performed once every five years.

First inspection for 

license renewal should 

be completed before 

the period of extended 

operation.

Non-Environmentally 

Qualified Electrical

Cable Connections 

A representative sample of electrical cable 

connections within the scope of license renewal 

will be tested at least once every 10 years. 

Testing may include thermography, contact 

resistance testing, or other appropriate testing 

methods.

First tests for license 

renewal should be 

completed before the 

period of extended 

operation.

Structures Monitoring 

Program

The program consists of periodic inspection and 

monitoring the condition of structures and 

structure 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.

Existing program.

Quality assurance The 10 CFR Part 50, Appendix B program 

provides for corrective actions, the confirmation 

process, and administrative controls for aging 

management programs for license renewal. The 

scope of this existing program will be expanded 

to include non safety-related structures and 

components that are subject to an AMR for 

license renewal.

Program should be 

implemented before 

the period of extended 

operation.
NUREG-1800, Rev. 1 3.6-14 September 2005

Table 3.6-2. FSAR Supplement for Aging Management of Electrical and 

Instrumentation and Control System

Program Description of Program

Implementation 

Schedule*

* 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.
September 2005 4-i NUREG-1800, Rev. 1

CHAPTER 4

TIME-LIMITED AGING ANALYSES
NUREG-1800, Rev. 1 4-ii September 2005

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September 2005 4.1-1 NUREG-1800, Rev. 1

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 section 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 question regarding the adequacy of the CLB must be 

addressed under the backfit rule (10 CFR 50.109) and is 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 is to include a 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;
NUREG-1800, Rev. 1 4.1-2 September 2005 

5. Involve conclusions or provide the basis for conclusions related to the capability of the 

system, structure, or component to perform its intended function(s), as delineated in 

10 CFR 54.4(b); and

6. Are contained or incorporated by reference in the CLB.

The reviewer is to review the FSAR Supplement for each TLAA that has been 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 should adhere to the 

following review procedures:

The reviewer should use the plant UFSAR and other CLB documents, such as staff SERs, in 

performing the review. The reviewer should select 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 

licensee’s methodology for identifying TLAAs may also be useful in identifying calculations that 

did not meet six criteria below.

1. Involve systems, structures, and components within the scope of license renewal, as 

delineated in 10 CFR 54.4(a). Chapter 2 of this standard review plan 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, loss of toughness, loss of prestress, settlement, cracking, and loss of dielectric 

properties.

3. Involve time-limited assumptions defined by the current operating term (for example, 

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 

should be 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 should make 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 licensee 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.
September 2005 4.1-3 NUREG-1800, Rev. 1

6. Are contained or incorporated by reference in the CLB. The CLB includes the technical 

specifications as well as design basis information (as defined in 10 CFR 50.2) or licensee 

commitments documented in the plant-specific documents contained or incorporated by 

reference in the CLB including, but not limited to: the FSAR, NRC SERs, the fire protection 

plan/hazards analyses, correspondence to and from the NRC, the quality assurance plan, 

and topical reports included as references to the FSAR. Calculations and analyses that are 

not 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 and 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 licensee 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 licensee’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 of this review plan section) 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 potential TLAAs 

(60 FR 22480). Table 4.1-3 provides a list of other plant-specific TLAAs that have been 

identified by the initial license renewal applicants. Tables 4.1-2 and 4.1-3 provide examples of 

analyses that potentially could be TLAAs for a particular plant. However, TLAAs are plantspecific and depend on an applicant’s CLB. It is not expected that all applicants would identify 

all the analyses in these tables as TLAAs for their plants. Also, an applicant may have 

performed specific TLAAs for its plant that are not shown in these tables.

Staff members from other branches of the Division of Engineering will be reviewing the 

application in their assigned areas without examining the identification of TLAAs. However, they 
NUREG-1800, Rev. 1 4.1-4 September 2005 

may come across situations in which they may question why the applicant did not identify 

certain analyses as TLAAs. The reviewer should coordinate the resolution of any such 

questions with these other staff members and 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 verifies that the applicant 

has also 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 will be used by the staff in its evaluation of 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.

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

Power Plants,” July 1981.
September 2005 4.1-5 NUREG-1800, Rev. 1

Table 4.1-1. Identification of 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. Potential Time-Limited Aging Analyses

Reactor vessel neutron embrittlement 

Concrete containment tendon prestress

Metal fatigue

Environmental qualification of electrical equipment 

Metal corrosion allowance 

Inservice flaw growth analyses that demonstrate structure stability for 40 years 

Inservice local metal containment corrosion analyses 

High-energy line-break postulation based on fatigue cumulative usage factor
NUREG-1800, Rev. 1 4.1-6 September 2005 

Table 4.1-3. Additional Examples of Plant-Specific TLAAs as Identified by the Initial 

License Renewal Applicants

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

Reactor vessel circumferential weld inspection relief (BWR)
September 2005 4.2-1 NUREG-1800, Rev. 1

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 (1) upper-shelf energy, (2) PTS for PWRs, (3) heat-up 

and cool-down (pressure-temperature limits) curves, (4) BWR Vessel and Internals Project 

(VIP) VIP-05 analysis for elimination of circumferential weld inspection and analysis of the axial 

welds, and (5) 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 should review 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 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 must 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. 1 4.2-2 September 2005

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 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 equivalent margins analysis (EMA) are reevaluated 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 licensees to take further 

corrective actions for those cases where the 75 ft-lb unirradiated USE (UUSE) criterion or 50 ftlbs end-of-life USE criterion cannot be met (i.e., when the respective UUSE value falls below 75 

ft-lb or the EOL USE falls below 50 ft-lb). 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-lb or where the projected USE value for a given material is projected to be less than 

the 50 ft-lb acceptance criteria at the expiration of the operating license. Thus, if the USE value 

for a PWR RV material, as projected to the expiration of the period of extended operation, falls 

below either the 50 ft-lb acceptance criterion or the USE value criterion specified in a previously 

NRC-approved EMA, or where the %-drop in USE value for a BWR RV material, as projected to 

the expiration of the period of extended operation, falls below that %-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 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 end of life (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.
September 2005 4.2-3 NUREG-1800, Rev. 1

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 reevaluated to consider the period of extended operation in accordance 

with 10 CFR 50.61. An analysis is performed in accordance with RG 1.154 (Ref. 3) if the “PTS 

screening criteria” in 10 CFR 50.61 are 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. 13) which states that if the applicant does not 

extend the TLAA, the applicant should provide 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 

will not need to be submitted as part of the LRA since the P-T limits will 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. 1 4.2-4 September 2005

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. 4-6). An applicant

for renewal of a license to operate such a BWR may provide justification to extend this relief into 

the period of extended operation in accordance with BWRVIP-74 (Ref 7). The staff’s review of 

BWRVIP-74 (Ref. 7) is contained in an October 18, 2001 letter to C.Terry, BWRVIP Chairman 

(Ref. 11). Section A.4.5 of Report BWRVIP-74 indicates that the staff’s SER conservatively 

evaluated BWR RPV’s to have 64 effective full power years (EFPY), which is 10 EFPY greater 

than what is realistically expected for the end of the license renewal period. Since this was a 

generic analysis, a licensee relying on BWRVIP-74 should provide plant-specific information to 

demonstrate that the circumferential beltline weld materials meet the criteria specified in the 

report and that operator training and procedures will be utilized during the license renewal term 

to limit the frequency for cold over-pressure events.

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. 8) 

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. 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 location described in the SER. Since the BWRVIP analysis was generic, a 

licensee relying on BWRVIP-74 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 May 7, 2000, 

(Ref. 8) letter.

4.2.2.2 FSAR Supplement

The specific criterion for meeting 10 CFR 54.21(d) is:
September 2005 4.2-5 NUREG-1800, Rev. 1

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).

4.2.3 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 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.

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 RG 1.99 Rev. 2 (Ref. 9) to project uppershelf energy to the end of the period of extended operation. The applicant may also use ASME 

Code Section XI Appendix K (Ref. 10) for the purpose of performing an equivalent margins 

analysis to demonstrate that adequate protection for ductile failure will be maintained to the end 

of the period of extended operation. The staff should review the applicant’s methodology for this 

evaluation. Branch Position MTEB 5-2 in Standard Review Plan Section 5.3.2, “Pressure 

Temperature limits,” provides additional NRC positions on estimations of USE values for reactor 

vessel beltline materials.

The staff should confirm 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 should have identified: (1) the neutron fluence at the 1/4T 

location for each beltline material at the expiration of the license renewal period; (2) the 

methodology used in determining the neutron fluence, and identified (3) whether the 

methodology followed the guidance in Regulatory Guide (RG) 1.190 (Ref. 12).

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 should determine whether:

1. For each beltline material, the applicant has provided the unirradiated Charpy USE, 

and the projected Charpy USE at the end of the license renewal period, and whether 
NUREG-1800, Rev. 1 4.2-6 September 2005

the drop in Charpy USE was determined using the limit lines in Figure 2 of RG 1.99, 

Revision 2 or from surveillance data and the percentage copper.

2. If an equivalent margins analysis was used to demonstrate compliance with the USE 

requirements in Appendix G of 10 CFR Part 50, the applicant has provided the 

analysis or identified an approved topical report that contains the analysis. 

Information the staff will consider 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 should confirm that the beltline materials are evaluated in 

accordance with Renewal Applicant Action Items 10, 11 and 12 in the staff’s SER, for BWRVIP74 (Letter to C. Terry dated October 18, 2001) (Ref.11). The applicant should also identify 

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 should provide analyses of the data to determine whether the data is consistent with 

the RG 1.99, Revision 2 methodology that was utilized in the BWRVIP-74 analyses.

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 will be reviewed on a case-bycase 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 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.

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 should confirm 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 inside surface and the 1/4T location for 

each beltline material at the expiration of the license renewal period. Identified the methodology 

used in determining the neutron fluence and identified whether the methodology followed the 

guidance in Regulatory Guide (RG) 1.190 (Ref. 12).

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 
September 2005 4.2-7 NUREG-1800, Rev. 1

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 

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 should 

provide 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 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 exceeded during the period of extended 

operation, an analysis based on RG 1.154 (Ref. 3) is reviewed.

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 should provide an assessment of the current licensing basis 

TLAA for PTS, a discussion of the flux reduction program implemented in accordance with 
NUREG-1800, Rev. 1 4.2-8 September 2005

§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 should explain 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 should:

(1) Identify the material in the RPV which has limiting RTPTS value,

(2) Provide the projected fluence value for the limiting material at end of license 

extended (EOLE),

(3) Provide the projected RTPTS value for the limiting material at EOLE, and 

(4) Provide the projected date and fluence values at which the limiting material 

will exceed the screening criteria in §50.61.

B. The applicant should discuss aging management programs that it intends to implement 

which will actively “manage” the condition of the facility’s RPV, and hence, the risk 

associated with PTS. This discussion would be expected to address, at least, the 

facility’s reactor pressure vessel material surveillance program.

C. The applicant should briefly discuss the options that it is considering with respect to 

“resolving” the PTS issue through EOLE. It is anticipated that this discussion would 

include 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)] and/or,

(4) The potential for RPV thermal annealing in accordance with §50.66 [see 

§50.61(b)(7)].

4.2.3.1.3 Pressure-Temperature (P-T) Limits 

4.2.3.1.3.1 10 CFR 54.21(c)(1)(i)

The documented results of the projected neutron fluence at the end of the period of extended 

operation are reviewed to verify that it is bound by the embrittlement assumed in the existing PT limit analysis.

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.
September 2005 4.2-9 NUREG-1800, Rev. 1

4.2.3.1.3.3 10 CFR 54.21(c)(1)(iii)

Not applicable.

4.2.3.1.4 Elimination of Circumferential Weld Inspection (for BWRs)

To demonstrate that the vessel has not been embrittled beyond the basis for the technical 

alternative and that cold over-pressure events are not likely to occur during the license renewal 

term, the applicant should provide: (1) a comparison of the neutron fluence, initial RTNDT , 

chemistry factor amounts of copper and nickel, delta RTNDT, and mean RTNDT of the limiting 

circumferential weld at the end of the license renewal period to the 64 EFPY reference case in 

Appendix E of the staff’s SER for BWRVIP-74 (Ref. 11), (2) 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 circumferential welds and the reference case, and (3) a description 

of procedures and training that will be utilized during the license renewal term to limit the 

frequency of cold over-pressure events to the amount specified in the staff’s SER for BWRVIP74 (Ref. 11). The staff should ensure that the applicant’s plant is bound by the BWRVIP-74 

analysis and that the applicant has committed to actions that are the basis for the staff approval.

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: (1) 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 (2) 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) on Topical Report BWRVIP-05, dated May 7, 

2000, 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.

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 

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 a 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.
NUREG-1800, Rev. 1 4.2-10 September 2005

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.”

2. 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events.”

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

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

4. BWRVIP-05, “BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Shell 

Weld Inspection Recommendations (BWRVIP-05),” Boiling Water Reactor Owners Group, 

September 28, 1995.

5. Letter to Carl Terry of Niagara Mohawk Power Company, from Gus C. Lainas of NRC, 

dated July 28, 1998.
September 2005 4.2-11 NUREG-1800, Rev. 1

6. 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,” Nuclear Regulatory Commission, November 10, 1998.

7. BWRVIP-74, “BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” 

Boiling Water Reactor Owners Group, September 1999.

8. Letter to Carl Terry of Niagara Mohawk Power Company, from Jack R. Strosnider, Jr., of 

NRC, dated March 7, 2000.

9. Regulatory Guide 1.99 Rev. 2, “Radiation Embrittlement of Reactor Vessel Materials,” May, 

1988. 

10. Appendix K of ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power 

Plant Components.”

11. Letter to Carl Terry of Niagara Mohawk Power Company, BWRVIP Chairman, from 

Christopher Grimes, of NRC, dated October 18, 2001.

12. Regulatory Guide 1.190 Rev. 0, “Calculational and Dosimetry Methods for Determining 

Pressure Vessel Neutron Fluence,” March 2001.

13. Letter to the Commission from L.A. Reyes (EDO), dated May 27, 2004 (ADAMS accession 

number ML041190564)
NUREG-1800, Rev. 1 4.2-12 September 2005

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 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 BWRVIP-74 as approved by the NRC and has 

provided sufficient information that the probability of vessel 

failure due to embrittlement of axial welds is low.

Completed

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 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 no later than the committed date.
September 2005 4.3-1 NUREG-1800, Rev. 1

4.3 METAL FATIGUE ANALYSIS

Review Responsibilities

Primary- Branch responsible for the TLAA issues

Secondary- None

4.3.1 Areas of Review

A metal component subjected to cyclic loading at loads less than the static design load may fail 

because of fatigue. 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.

The metal fatigue analysis review includes, as appropriate, a review of in service flaw growth 

analyses, reactor vessel underclad cracking analysis, reactor vessel internals fatigue analysis, 

postulated high energy line break, leak-before-break, RCP flywheel, and metal bellows. 

4.3.1.1 Time-Limited Aging Analysis

Metal components may be designed or analyzed based on requirements in the American 

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code or the American 

National Standards Institute (ANSI) guidance. These codes contain explicit metal fatigue or 

cyclic considerations based on TLAAs.

4.3.1.1.1 ASME Section III, Class 1

ASME Class 1 components, which include core support structures, are analyzed for metal 

fatigue. ASME Section III (Ref. 1) requires a fatigue analysis for Class 1 components that 

considers all transient loads based on the anticipated number of transients. A Section III 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 of less than or equal to one for acceptable fatigue design. 

The fatigue resistance of these components during the period of extended operation is an area 

of review.

4.3.1.1.2 ANSI B31.1

ANSI B31.1 (Ref. 2) applies only to piping. It does not call for an explicit fatigue analysis. It 

specifies allowable stress levels based on the number of anticipated thermal cycles. The 

specific allowable stress reductions due to thermal cycles are listed in Table 4.3-1. For example, 

the allowable stress would be reduced by a factor of 1.0, i.e., no reduction, for piping that is not 

expected to experience more than 7,000 thermal cycles during plant service, but would be 

reduced to half of the maximum allowable static stress for 100,000 or more thermal cycles. The 

fatigue resistance of these components during the period of extended operation is an area of 

review.

4.3.1.1.3 Other Evaluations Based on CUF

The codes also contain metal fatigue analysis criteria 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 
NUREG-1800, Rev. 1 4.3-2 September 2005 

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)]. For these components, the discussion relating to ASME 

Section III, Class 1 in Subsection 4.3.1.1.1 of this review plan section applies.

4.3.1.1.4 ASME Section III, Class 2 and 3

ASME Section III, Class 2 and 3 piping cyclic design requirements are similar to the guidance in 

ANSI B31.1. The discussion relating to B31.1 in Subsection 4.3.1.1.2 of this review plan section 

applies.

4.3.1.2 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 GSI-166 

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 
September 2005 4.3-3 NUREG-1800, Rev. 1

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 10-2 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 through-wall 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 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.

4.3.1.3 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.

4.3.2 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:

4.3.2.1.1 ASME Section III, Class 1

For components designed or analyzed to ASME Class 1 requirements, the acceptance criteria, 

depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:
NUREG-1800, Rev. 1 4.3-4 September 2005 

4.3.2.1.1.1 10 CFR 54.21(c)(1)(i)

The existing CUF calculations remain valid because the number of assumed transients would 

not be exceeded during the period of extended operation.

4.3.2.1.1.2 10 CFR 54.21(c)(1)(ii)

The CUF calculations have been reevaluated based on an increased number of assumed 

transients to bound the period of extended operation. The resulting CUF remains less than or 

equal to unity for the period of extended operation.

4.3.2.1.1.3 10 CFR 54.21(c)(1)(iii)

In Chapter X 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 reactor coolant 

system components. The staff has determined that this program is an acceptable aging 

management program to 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 

should also 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 ANSI B31.1

For piping designed or analyzed to B31.1, the acceptance criteria, depending on the applicant’s 

choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:

4.3.2.1.2.1 10 CFR 54.21(c)(1)(i)

The existing fatigue strength reduction factors remain valid because the number of 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 fatigue strength reduction factors have been reevaluated based on an increased number of 

assumed thermal cycles and the stress reduction factors (e.g., Table 4.3-1) given in the 

applicant’s code of record to bound the period of extended operation. The adjusted fatigue 

strength reduction factors are such that the component design basis remains valid 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. 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.
September 2005 4.3-5 NUREG-1800, Rev. 1

Alternative 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 functions(s) will be maintained during the period of extended operation.

4.3.2.1.3 Other Evaluations Based on CUF

The acceptance criteria in Subsection 4.3.2.1.1 of this review plan section apply.

4.3.2.1.4 ASME Section III, Class 2 and 3

The acceptance criteria in Subsection 4.3.2.1.2 of this review plan section apply.

4.3.2.2 Generic Safety Issue

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. 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). The sample of critical components can 

be evaluated by applying environmental correction factors to the existing ASME Code fatigue 

analyses. Formulas for calculating the environmental life correction factors for carbon and lowalloy steels are contained in NUREG/CR-6583 (Ref. 14) and those for austenitic SSs are 

contained in NUREG/CR-5704 (Ref. 15).

4.3.2.3 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 following review procedures should 

be followed:

4.3.3.1 Time-Limited Aging Analysis

4.3.3.1.1 ASME Section III, Class 1

For components designed or analyzed to ASME Class 1 requirements, the review procedures, 

depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:
NUREG-1800, Rev. 1 4.3-6 September 2005 

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.

4.3.3.1.1.2 10 CFR 54.21(c)(1)(ii)

The operating transient experience and a list of the increased number of assumed transients 

projected to the end of the period of extended operation are reviewed to ensure that the 

transient projection is adequate. The revised CUF calculations based on the projected number 

of assumed transients are reviewed to ensure that the CUF remains less than or equal to one at 

the end of the period of extended operation.

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 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 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. No further staff evaluation is necessary.

4.3.3.1.2 ANSI B31.1

For piping designed or analyzed to ANSI B31.1 guidance, the review procedures, depending on 

the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are:

4.3.3.1.2.1 10 CFR 54.21(c)(1)(i)

The operating cyclic experience and a list of the assumed thermal cycles used in the existing 

allowable stress determination are reviewed to ensure that the number of assumed thermal 

cycles would not be exceeded during the period of extended operation.

4.3.3.1.2.2 10 CFR 54.21(c)(1)(ii)

The operating cyclic experience and a list of the increased number of assumed thermal cycles 

projected to the end of the period of extended operation are reviewed to ensure that the thermal 

cycle projection is adequate. The revised allowable stresses based on the projected number of 

assumed thermal cycles and the stress reduction factors given in the applicant’s code of record 

are reviewed to ensure that they remain sufficient as specified by the code during the period of 

extended operation. Typical stress reduction factors based on thermal cycles are given in Table 

4.3-1.
September 2005 4.3-7 NUREG-1800, Rev. 1

The code of record should be used for the reevaluation, or the applicant may use the criteria of 

10 CFR 50.55a. In the latter case, the reviewer verifies that the requirements in 10 CFR 50.55a 

are met.

4.3.3.1.2.3 10 CFR 54.21(c)(1)(iii)

The applicant’s proposed program to ensure that the effects of aging on the intended function(s) 

will be adequately managed for the period of extended operation is reviewed. If the applicant 

proposed a component replacement before it exceeds the assumed thermal cycles, the 

reviewer verifies that the allowable stresses for the replacement will remain sufficient as 

specified by the code during the period of extended operation. Other applicant-proposed 

programs will be reviewed on a case-by-case basis.

4.3.3.1.3 Other Evaluations Based on CUF

The review procedures in Subsection 4.3.3.1.1 of this review plan section apply.

4.3.3.1.4 ASME Section III, Class 2 and 3

The review procedures in Subsection 4.3.3.1.2 of this review plan section apply.

4.3.3.2 Generic Safety Issue

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, as a minimum, those selected in NUREG/CR-6260 

(Ref. 10).

2. The sample of critical components has been evaluated by applying environmental correction 

factors to the existing ASME Code fatigue analyses.

3. Formulas for calculating the environmental life correction factors are those contained in 

NUREG/CR–6583 (Ref. 14) for carbon and low-alloy steels, and in NUREG/CR-5704 

(Ref. 15) for austenitic SSs, or an approved technical equivalent.

4.3.3.3 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. 

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 
NUREG-1800, Rev. 1 4.3-8 September 2005 

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 Boiler and Pressure Vessel Code, Section III, “Rules for Construction of Nuclear 

Power Plant Components,” American Society of Mechanical Engineers.

2. ANSI/ASME B31.1, “Power Piping,” American National Standards Institute.

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, “A Prioritization of Generic Safety Issues,” Supplement 20, July 1996.
September 2005 4.3-9 NUREG-1800, Rev. 1

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),” U.S. Nuclear Regulatory 

Commission, March 2001.

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.
NUREG-1800, Rev. 1 4.3-10 September 2005 

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 will address 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. The sample of critical components 

can be evaluated by applying environmental correction factors to 

the existing ASME Code fatigue analyses. Formulas for calculating 

the environmental life correction factors are contained in 

NUREG/CR-6583 for carbon and low-alloy steels and in 

NUREG/CR-5704 for austenitic SSs.

Evaluation should 

be completed 

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.
September 2005 4.4-1 NUREG-1800, Rev. 1

4.4 ENVIRONMENTAL QUALIFICATION (EQ) OF ELECTRIC EQUIPMENT

Review Responsibilities

Primary- Branch responsible for electrical engineering

Secondary– Plant Systems Branch (Mechanical Equipment only)

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 

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. 1 4.4-2 September 2005

its intended functions during accident conditions after experiencing the effects of in-service 

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 will be reviewed for the period of extended operation 

according to those requirements. If a qualified life was not previously established, the 

qualification will be 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, will be 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, will be 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. 16) to inform 

addressees of the results of the technical assessment of GSI-168, "Environmental Qualification 

of Electrical Equipment," (Ref. 10). 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,
September 2005 4.4-3 NUREG-1800, Rev. 1

(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 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 CLB. 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. 14), 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 Generic Safety Issue

Not applicable.
NUREG-1800, Rev. 1 4.4-4 September 2005

4.4.2.3 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).

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 will be 

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 
September 2005 4.4-5 NUREG-1800, Rev. 1

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.

4.4.3.2 Generic Safety Issue

Not applicable.

4.4.3.3 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 that 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 
NUREG-1800, Rev. 1 4.4-6 September 2005

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.

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. Deleted.

9. Deleted. 

10. NUREG-0933, “A Prioritization of Generic Safety Issues,” Supplement 20, July 1996.

11. Deleted.

12. Deleted. 

13. Deleted. 

14. NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear Regulatory 

Commission, July 2001.

15. Deleted.

16. NRC Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

 Instrumentation and Control Cables” dated May 2, 2003.
September 2005 4.4-7 NUREG-1800, Rev. 1

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 (that is, 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 (that is, 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 case-by-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. 1 4.4-8 September 2005

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.
September 2005 4.5-1 NUREG-1800, Rev. 1

4.5 CONCRETE CONTAINMENT TENDON PRESTRESS ANALYSIS

Review Responsibilities

Primary- Branch responsible for structural engineering 

Secondary- None

4.5.1 Areas of Review

The prestressing tendons in prestressed concrete containments 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 forty 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 of this review plan 

section delineate acceptable methods for meeting the requirements of the NRC’s regulations in 

10 CFR 54.21(c)(1).

4.5.2.1 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 (1) losses of the prestressing 

force are less than the predicted losses as evidenced from the trend lines constructed from the 

recent inspection, (2) the period of evaluation covers the period of extended operation, and 

(3) 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. 1 4.5-2 September 2005

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 has 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 should be treated in 

the same manner as an approved topical report. However, the GALL report contains one 

acceptable way and not the only way to manage aging for license renewal.

In referencing the GALL report, an 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. An applicant 

should also verify 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 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).

4.5.3 Review Procedures

For each area of review described in Subsection 4.5.1 of this review plan section, 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:
September 2005 4.5-3 NUREG-1800, Rev. 1

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 should verify 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 should consider 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.

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. 

Table 4.5-1 of this review plan section contains examples of acceptable FSAR supplement 
NUREG-1800, Rev. 1 4.5-4 September 2005

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 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 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.
September 2005 4.5-5 NUREG-1800, Rev. 1

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),” U.S. Nuclear Regulatory 

Commission, Revision 1, September 2005.
NUREG-1800, Rev. 1 4.5-6 September 2005

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

TLAA Evaluation

10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(ii) Example

TLAA Description of Evaluation

Implementation 

Schedule*

Concrete

containment

tendon

prestress

The prestressing tendons are used to impart compressive forces 

in the prestressed concrete containments to resist the internal 

pressure inside the containment that would be generated in the 

event of a LOCA. The prestressing forces generated by the 

tendons diminish over time due to losses in prestressing forces 

in the tendons and in the surrounding concrete. The 

prestressing force 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)(ix)(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.
September 2005 4.6-1 NUREG-1800, Rev. 1

4.6 CONTAINMENT LINER PLATE, METAL CONTAINMENTS, AND PENETRATIONS 

FATIGUE ANALYSIS

Review Responsibilities

Primary- Branch responsible for structural engineering

Secondary- Branch responsible for mechanical engineering

4.6.1 Areas of Review

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 in. 

(6.2 mm) and 3/8 in. (9.5 mm). The liner plates are attached to the concrete containment wall by 

stud anchors or structural rolled shapes or both. The design process assumes that the liner 

plates do not carry loads. However, 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-base conditions, the liner plates could experience 

significant strains. Some plants may have metal containments instead of concrete containments 

with liner plates. 

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. 

High energy piping penetrations and the fuel transfer canal in some plants are equipped with 

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 to provide leak-tight penetrations.

The containment liner plates, metal containments, 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 the effects of aging on the intended functions will be 

adequately managed for the period of extended operation.

The adequacy of the fatigue analyses of the containment liner plates (including welded joints), 

metal containments, 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 Section 

4.3, “Metal Fatigue,” of this review plan.
NUREG-1800, Rev. 1 4.6-2 September 2005

4.6.1.1 Time-Limited Aging Analysis

The containment liner plates (including welded joints), metal containments, 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. 1) 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 may also 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 of this 

review plan section, 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 of this review plan 

section delineate acceptable methods for meeting the requirements of the NRC’s regulations in 

10 CFR 54.21(c)(1).

4.6.2.1 Time-Limited Aging Analysis

Pursuant to 10 CFR 54.21(c)(1), 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.
September 2005 4.6-3 NUREG-1800, Rev. 1

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, 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 should be reevaluated 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) should be reevaluated and revised as 

necessary. The revised analysis should show that the CUF will 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)

The effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. The component could be replaced; the CUF for the replacement must be 

less than or equal to one during the period of extended operation.

An alternative aging management program provided by the applicant 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. In cases where a 

mitigation or inspection program is proposed, the aging management program may be 

evaluated against the 10 elements described in Branch Technical Position RLSB-1 

(Appendix A.1 of this standard review plan).

4.6.2.1.2 Other Evaluations Based on CUF

The acceptance criteria in Subsection 4.6.2.1.2 of this review plan section 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 the TLAAs regarding the basis for 

determining that the applicant has made the demonstration required by 10 CFR 54.21(c)(1).
NUREG-1800, Rev. 1 4.6-4 September 2005

4.6.3 Review Procedures

For each area of review described in Subsection 4.6.1 of this review plan section, the following 

review procedures should be 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, 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 54.2l(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 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.

4.6.3.1.1.3 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) will be adequately managed for the period of extended operation is 

reviewed. If the applicant proposed 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.

Other applicant proposed programs will be 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 of this review plan section apply.

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, and penetrations fatigue TLAA. Table 4.6-1 of this review plan section 
September 2005 4.6-5 NUREG-1800, Rev. 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 4.6-1. 

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 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 evaluation concludes 

that the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1), that, for the containment liner plate or metal containment, 

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, 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.

4.6.6 References

1. ASME Boiler and Pressure Vessel Code, Section III, Division 2, “Code for Concrete Reactor 

Vessels and Containments,” Subsection CC, “Concrete Containment,” and Division 1, 

Subsection NE, “MC Components,” American Society of Mechanical Engineers, New York, 

New York, 1989 or other editions as approved in 10 CFR 50.55a.
NUREG-1800, Rev. 1 4.6-6 September 2005

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), liner 

weld joints, penetration sleeves, dissimilar metal welds, and 

penetration bellows provide a 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), liner 

weld joints, penetration sleeves, dissimilar metal welds, and 

penetration bellows provide a 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), liner 

weld joints, penetration sleeves, dissimilar metal welds, and 

penetration bellows provide a 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.

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.
September 2005 4.7-1 NUREG-1800, Rev. 1

4.7 OTHER PLANT-SPECIFIC TIME-LIMITED AGING ANALYSES

Review Responsibilities

Primary- 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 time-limited aging analyses (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 standard review plan.

TLAAs may have evolved since issuance of a plant’s operating license, and are plant-specific. 

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 question regarding the adequacy of the 

CLB must be addressed under the backfit rule (10 CFR 50.109) and is 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 function of those systems, structures, or components will be 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 standard review plan.

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.

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.
NUREG-1800, Rev. 1 4.7-2 September 2005

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 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).

4.7.3 Review Procedures

For certain applicants, plant-specific analyses may meet the definition of a TLAA as given in 

10 CFR54.3. The concern for License Renewal is that these analyses may not have properly 

considered the length of the extended period of operation, the consideration of 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 will provide 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 of this review plan section, 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:

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.
September 2005 4.7-3 NUREG-1800, Rev. 1

The applicant should describe 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 should show that (1) conditions and assumptions used in the 

analysis already address the relevant aging effects for the period of extended operation, and 

(2) 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 should be provided 

by the applicant. The reviewer should assure 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, for 

example, 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 

may also 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 document 

the results of the reanalysis to show that it is satisfactory for the 60-year period.

As applicable, the plant’s 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.

In some cases, 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 should be provided 

by the applicant. The reviewer should assure 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 would propose to manage the aging effects associated with the 

TLAA by an aging management program in the same manner as would be described in the IPA 

in 10 CFR 54.21(a)(3). The reviewer reviews the applicant’s aging management program to 

verify that the effects of aging on the intended function(s) will be adequately managed 

consistent with the CLB for the period of extended operation.

The applicant should identify the structures and components associated with the TLAA. The 

TLAA should be described with respect to the objectives of the analysis, conditions, 
NUREG-1800, Rev. 1 4.7-4 September 2005

assumptions used, acceptance criteria, relevant aging effects, and intended function(s). In 

cases where a mitigation or inspection program is proposed, the reviewer may use 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 will be 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 will complete 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 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 (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 

Supplement contains an appropriate summary description of this TLAA 

evaluation for the period of extended operation as reflected in the license 

condition.
September 2005 4.7-5 NUREG-1800, Rev. 1

4.7.5 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.

4.7.6 References

None
NUREG-1800 4.7-6 April 2001

This Page Intentionally Left Blank
September 2005 A-i NUREG-1800, Rev. 1

APPENDIX A

BRANCH TECHNICAL POSITIONS
NUREG-1800, Rev. 1 A-ii September 2005

This Page Intentionally Left Blank
September 2005 A.1-1 NUREG-1800, Rev. 1

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) 

will be adequately managed so that 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 CLB during the period of 

extended operation.

Aging management programs are generally of four types: 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 erosion-corrosion 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 of heat balances on heat exchangers to transfer heat is tested. 

More than one type of aging management program 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 degradations 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 should also 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. 1 A.1-2 September 2005

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 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 provides relevance to aid 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 water chemistry, coating, or cathodic protection as an aging 

management program.

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 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.

DBEs are abnormal events; they include: design basis pipe break, LOCA, and safe 

shutdown earthquake (SSE). Potential degradations 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 

occur, and the leakage could cause corrosion. Thus, the aging effects from leakage of 

bolted connections should be evaluated for license renewal.
September 2005 A.1-3 NUREG-1800, Rev. 1

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 aging management program 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 aging management programs/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 aging management program. Probabilistic arguments may be used to 

assist in developing 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 aging management program for the structure or component for 

license renewal, but may not be used to conclude that no aging management program is 

necessary for license renewal.

A.1.2.3 Aging Management Program Elements

A.1.2.3.1 Scope of Program

1. The specific program necessary for license renewal should be identified. The scope of the 

program should include the specific structures and components of which the program 

manages the aging.

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. For condition or performance monitoring programs, they do not rely on preventive actions 

and thus, this information need not be provided. More than one type of aging management 

program may be implemented to ensure that aging effects are managed.
NUREG-1800, Rev. 1 A.1-4 September 2005

A.1.2.3.3 Parameters Monitored or Inspected

1. The parameters to be monitored or inspected should be identified and linked to the 

degradation of the particular structure and component intended function(s).

2. For a condition monitoring program, the parameter monitored or inspected should detect 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.

A performance monitoring program may not ensure the structure and component intended 

function(s) without linking the degradation of passive intended functions with the 

performance being monitored. For example, a periodic diesel generator test alone would not 

provide assurance that the diesel will start and run properly under all applicable design 

conditions. While the test verifies that the diesel will perform if all the support systems 

function, it provides little information related to the material condition of the support 

components and their ability to withstand DBE loads. Thus, a DBE, such as a seismic event, 

could cause the diesel supports, such as the diesel embedment plate anchors or the fuel oil 

tank, to fail if the effects of aging on these components are not managed during the period 

of extended operation.

4. For prevention and 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. This includes 

aspects such as method or technique (e.g., visual, volumetric, surface inspection), 

frequency, sample size, data collection and timing of new/one-time inspections to ensure 

timely detection of aging effects. Provide information that links the parameters to be 

monitored or inspected to the aging effects being managed.

2. Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth 

principles. A degraded or failed component reduces the reliability of the system, challenges 

safety systems, and contributes to plant risk. Thus, the effects of aging on a structure or 

component should be managed to ensure its availability to perform its intended function(s) 

as designed when called upon. In this way, all system level intended function(s), including 

redundancy, diversity, and defense-in-depth consistent with the plant’s CLB, would be 
September 2005 A.1-5 NUREG-1800, Rev. 1

maintained for license renewal. A program based solely on detecting structure and 

component failure should not be considered as an effective aging management program for 

license renewal.

3. This program element describes “when,” “where,” and “how” program data are collected 

(i.e., all aspects of activities to collect data as part of the program).

4. The method or technique and frequency may be linked to plant-specific or industry-wide 

operating experience. Provide justification, including codes and standards referenced, that 

the technique and frequency are adequate to detect the aging effects before a loss of SC 

intended function. A program based solely on detecting SC failures is not considered an 

effective aging management program.

5. When sampling is used to inspect a group of SCs, provide the basis for the inspection 

population and sample size. The inspection population should be based on such aspects of 

the SCs as a similarity of materials of construction, fabrication, procurement, design, 

installation, operating environment, or aging effects. The sample size should be based on 

such aspects of the SCs as the specific aging effect, location, existing technical information, 

system and structure design, materials of construction, service environment, or previous 

failure history. The samples should be biased toward locations most susceptible to the 

specific aging effect of concern in the period of extended operation. Provisions should also 

be included on expanding the sample size when degradation is detected in the initial 

sample.

A.1.2.3.5 Monitoring and Trending

1. Monitoring and trending activities should be described, and they should provide predictability 

of the extent of degradation and thus effect timely corrective or mitigative actions. Plantspecific and/or industry-wide 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 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 acceptance criteria of the program and its basis should be described. The acceptance 

criteria, against which the need for corrective actions will be evaluated, should ensure that 

the structure and component intended function(s) are maintained under all CLB design 

conditions during the period of extended operation. The program should include a 

methodology for analyzing the results against applicable acceptance criteria.
NUREG-1800, Rev. 1 A.1-6 September 2005

For example, carbon steel pipe wall thinning may occur under certain conditions due to 

erosion-corrosion. An aging management program for erosion-corrosion 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 

reaching this acceptance criterion. This piping may be designed for thermal, pressure,

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 the FSAR because that is a part of the CLB. 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.

4. Qualitative inspections should be performed to same predetermined criteria as quantitative 

inspections by personnel in accordance with ASME Code and through approved site specific 

programs.

A.1.2.3.7 Corrective Actions

1. Actions to be taken when the acceptance criteria are not met should be described. 

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) will be maintained consistent 

with the CLB.

A.1.2.3.8 Confirmation Process

1. The confirmation process should be described. It should ensure 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 may also 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 were completed, the root cause determination was performed, and 

recurrence is prevented.
September 2005 A.1-7 NUREG-1800, Rev. 1

A.1.2.3.9 Administrative Controls

1. The administrative controls of the program should be described. They should provide a 

formal review and approval process.

2. Any aging management programs 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 includes 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. Operating experience with existing programs should be discussed. The operating 

experience of aging management programs, including past corrective actions resulting in 

program enhancements or additional programs, should be considered. A past failure would 

not necessarily invalidate an aging management program 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 component intended function(s) will be 

maintained during the period of extended operation.

2. An applicant may have to commit to providing operating experience in the future 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, March 2001
NUREG-1800, Rev. 1 A.1-8 September 2005

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

Element Description

1. Scope of program Scope of program should include 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 component intended 

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 Operating experience of the aging management program, 

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.
September 2005 A.2-1 NUREG-1800, Rev. 1

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 will be maintained consistent with the 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 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 Appendix A.1 (Branch Technical Position 

RLSB-1). The confirmation process should ensure that preventive actions are adequate and that 

appropriate corrective actions have been completed and are effective. Administrative controls 

should provide 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 elements of aging management programs for license 

renewal.

A.2.2 Branch Technical Position

1. Safety-related structures and components 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 structures and components that are subject to an AMR for license 

renewal, an applicant has an option to expand the scope of its 10 CFR Part 50 Appendix B 

program to include these structures and components to address corrective actions, the 

confirmation process, and administrative controls for aging management during the period of 

extended operation. The reviewer should verify that the applicant has documented such a 

commitment in the FSAR supplement in accordance with 10 CFR 54.21(d).

3. If an applicant chooses to have alternative means to address corrective actions, the 

confirmation process, and administrative controls for managing aging of nonsafety-related 

structures and components that are subject to an AMR for license renewal, the applicant’s 

proposal should be reviewed on a case-by-case basis following the guidance in 

Appendix A.1 (Branch Technical Position RLSB-1.)

A.2.3 References

1. Draft NUREG-1801, “Generic Aging Lessons Learned (GALL),” U.S. Nuclear 

Regulatory Commission, Revision 1, September 2005.
NUREG-1800, Rev. 1 A.2-2 September 2005

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September 2005 A.3-1 NUREG-1800, Rev. 1

A.3 GENERIC SAFETY ISSUES RELATED TO AGING 

(BRANCH TECHNICAL POSITION RLSB-2)

A.3.1 Background

Unresolved Safety Issues (USIs) and Generic Safety Issues (GSIs) are identified and tracked in 

the NRC’s formal resolution process set forth in NUREG-0933, “A Prioritization 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 should be specifically addressed. The version of NUREG-0933 that is current on the 

date 6 months before the date of the license renewal application should be 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 determined to be 

applicable to the applicant’s plant. New issues may be 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 may be generically 

applicable to other nuclear plants. If issues may 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 have been evaluated for the period of extended operation.
NUREG-1800, Rev. 1 A.3-2 September 2005

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 should be 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) would be available to adequately manage the effects of aging. An applicant would 

have to describe the basis for concluding that the CLB is maintained during the period of 

extended operation, and briefly describe options that are technically feasible during the 

period of extended operation to manage the effects of aging, but would not have to preselect 

which option would be used.

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, would remove 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, “A Prioritization of Generic Safety Issues.” 

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.
September 2005 A.3-3 NUREG-1800, Rev. 1

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 addresses 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).
NUREG-1800, Rev. 1 A.3-4 September 2005

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