Standard Review Plan

for Renewal of Specific 

Licenses and Certificates of 

Compliance for Dry Storage 

of Spent Nuclear Fuel

Draft Report for Comment

Office of Nuclear Material Safety and Safeguards

NUREG-1927, Rev. 1
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Standard Review Plan

for Renewal of Specific 

Licenses and Certificates of 

Compliance for Dry Storage 

of Spent Nuclear Fuel

Draft Report for Comment

Manuscript Completed: June 2015

Date Published: June 2015

Office of Nuclear Material Safety and Safeguards

NUREG-1927, Rev. 1
COMMENTS ON DRAFT REPORT

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iii

1 ABSTRACT

2 This Standard Review Plan is intended for use by the U.S. Nuclear Regulatory Commission 

3 (NRC) reviewer. It provides guidance for the safety review of renewal applications for specific 

4 licenses of independent spent fuel storage installations and certificates of compliance (CoC) of

5 dry storage systems, as codified in Title 10 of the Code of Federal Regulations (10 CFR) 

6 Part 72, “Licensing Requirements for the Independent Storage of Spent Nuclear Fuel and 

7 High-Level Radioactive Waste, and Reactor-Related Greater Than Class C Waste.”

8 To renew a specific license, an applicant (i.e., licensee) must submit a license renewal 

9 application at least 2 years before the expiration of the license in accordance with the 

10 requirements of 10 CFR 72.42(b). To renew a CoC, an applicant (i.e., CoC holder, user, or 

11 user’s representative) must submit a renewal application at least 30 days before the expiration 

12 of the associated CoC in accordance with the requirements of 10 CFR 72.240(b). The NRC 

13 may renew a specific license or a CoC for a term not to exceed 40 years, in accordance with 

14 10 CFR 72.42(a), or 10 CFR 72.240(a), respectively. General licenses are not renewed since 

15 the general-license term is linked to the storage term of the CoC in use.

16 The NRC may revise and update this Standard Review Plan to clarify the content, correct 

17 errors, or incorporate modifications approved by the Division of Spent Fuel Management. 

18 Comments, suggestions for improvement, and notices of errors or omissions should be sent to 

19 the Director, Division of Spent Fuel Management, U.S. Nuclear Regulatory Commission, 

20 Washington, DC 20555-0001.

21 Paperwork Reduction Act Statement

22 This NUREG contains information collection requirements that are subject to the Paperwork 

23 Reduction Act of 1995 (44 U.S.C. 3501 et seq.). The Office of Management and Budget (OMB) 

24 approved these information collections under OMB control number 3150-0132.

25 Public Protection Notification

26 The NRC may not conduct or sponsor, and a person is not required to respond to, a request for 

27 information or an information collection requirement unless the requesting document displays a 

28 currently valid OMB control number.

v

1

2 CONTENTS

3 ABSTRACT.......................................................................................................................... iii

4 LIST OF FIGURES ............................................................................................................. vii

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

6 ABBREVIATIONS................................................................................................................ ix

7 INTRODUCTION ..................................................................................................................1

8 1. GENERAL INFORMATION REVIEW ........................................................................5

9 1.1 Review Objective ...........................................................................................5

10 1.2 Areas of Review.............................................................................................5

11 1.3 Regulatory Requirements ..............................................................................5

12 1.4 Review Guidance...........................................................................................6

13 1.4.1 General Information............................................................................6

14 1.4.2 Financial Information ..........................................................................7

15 1.4.3 Environmental Report.........................................................................7

16 1.4.4 Application Content ............................................................................7

17 1.4.5 Timely Renewal..................................................................................9

18 1.4.6 Amendment Applications Submitted During the Renewal

19 Review or After the Renewal is Issued ...............................................9

20 1.4.7 Conditions to Specific Licenses and CoCs in the Period of

21 Extended Operation .........................................................................11

22 1.5 Evaluation Findings......................................................................................11

23 2. SCOPING EVALUATION ........................................................................................13

24 2.1 Review Objective .........................................................................................13

25 2.2 Areas of Review...........................................................................................13

26 2.3 Regulatory Requirements ............................................................................13

27 2.4 Review Guidance.........................................................................................14

28 2.4.1 Scoping Process ..............................................................................14

29 2.4.2 Structures, Systems, and Components within the Scope

30 of Renewal .......................................................................................17

31 2.4.2.1 Scoping of Dry Storage System Internals .........................17

32 2.4.2.2 Scoping of Reinforced Concrete Pads ..............................18

33 2.4.3 Structures, Systems, and Components not within the Scope of 

34 Renewal ...........................................................................................18

35 2.5 Evaluation Findings......................................................................................18

36 3. AGING MANAGEMENT REVIEW ...........................................................................21

37 3.1 Review Objective .........................................................................................21

38 3.2 Areas of Review...........................................................................................21

39 3.3 Regulatory Requirements ............................................................................24

40 3.4 Materials, Service Environments, Aging Mechanisms and Effects,

41 and Aging Management Activities ................................................................25

42 3.4.1 Review Guidance .............................................................................25

43 3.4.1.1 Identification of Materials and Environments.....................25

44 3.4.1.2 Identification of Aging Mechanisms and Effects ................26

45 3.4.1.3 Aging Management Activities............................................27

46 3.4.1.4 Aging Management Review for Dry Storage System

47 Internals............................................................................27
vi

1 3.4.2 Evaluation Findings ..........................................................................28

2 3.5 Time-Limited Aging Analyses.......................................................................28

3 3.5.1 Review Guidance .............................................................................29

4 3.5.2 Evaluation Findings ..........................................................................30

5 3.6 Aging Management Programs......................................................................30

6 3.6.1 Review Guidance .............................................................................31

7 3.6.1.1 Scope of Program ...........................................................31

8 3.6.1.2 Preventive Actions ..........................................................32

9 3.6.1.3 Parameters Monitored or Inspected ................................32

10 3.6.1.4 Detection of Aging Effects...............................................32

11 3.6.1.5 Monitoring and Trending .................................................33

12 3.6.1.6 Acceptance Criteria.........................................................33

13 3.6.1.7 Corrective Actions...........................................................34

14 3.6.1.8 Confirmation Process......................................................35

15 3.6.1.9 Administrative Controls ...................................................35

16 3.6.1.10 Operating Experience .....................................................35

17 3.6.2 Commencement of AMP(s) for CoC Renewals.................................39

18 3.6.3 Implementation of AMP(s)................................................................39

19 3.6.4 Evaluation Findings ..........................................................................39

20 4. CONSOLIDATED REFERENCES...........................................................................41

21 5. GLOSSARY.................. .......................................................................................45

22 APPENDICES

23 APPENDIX A NON-QUANTIFIABLE TERMS.......................................................... A-1

24 APPENDIX B EXAMPLES OF AGING MANAGEMENT PROGRAMS..................... B-1

25 APPENDIX C LEAD SYSTEM INSPECTION FOR SPECIFIC LICENSE AND

26 CERTIFICATE OF COMPLIANCE RENEWALS................................ C-1

27 APPENDIX D SUPPLEMENTAL GUIDANCE FOR THE USE OF A

28 DEMONSTRATION PROGRAM AS A SURVEILLANCE

29 TOOL FOR CONFIRMATION OF INTEGRITY OF HIGH

30 BURNUP FUEL DURING THE PERIOD OF EXTENDED

31 OPERATION.................................................................................. D-1

32 APPENDIX E CONSIDERATIONS FOR RENEWALS OF

33 CERTIFICATES OF COMPLIANCE.................................................. E-1

34 APPENDIX F STORAGE TERMS ............................................................................F-1

35
vii

1 LIST OF FIGURES

2 Figure A Specific License or CoC Renewal Process ....................................................3

3 Figure 2-1 Flowchart of Scoping Evaluation Process ....................................................16

4 Figure 3-1 Flowchart of AMR Process...........................................................................22

5 Figure 3-2 Learning AMP...........................................................................................38

6 Figure F-1 Flowchart for Calculating Storage Terms.................................................F-2

7 LIST OF TABLES

8 Table 1-1 Relationship of Regulations and General Information Review........................6

9 Table 2-1 Relationship of Regulations and Scoping Review ........................................13

10 Table 3-1 Relationship of Regulations and Aging Management Reviews.....................24

11 Table A-1 Screening Criteria for Non-Quantifiable Terms........................................... A-2

12 Table B-1 Example AMP for Localized Corrosion and Stress Corrosion Cracking

13 of Welded Stainless Steel Dry Storage Containers .................................... B-2

14 Table B-2 Example AMP for Reinforced Concrete Structures................................... B-12

15 Table B-3 Example of a High Burnup Fuel Monitoring and Assessment

16 Program................................................................................................ B-19

17 Table B-4 Formal Evaluations of Aggregate Information on HBU Fuel

18 Performance......................................................................................... B-25

19

ix

1

2 ABBREVIATIONS

3

4 ACI American Concrete Institute

5 AMA aging management activity

6 AMP aging management program

7 AMR aging management review

8 ANS American Nuclear Society

9 ANSI American National Standard Institute

10 ASME American Society of Mechanical Engineers

11 ASTM American Society for Testing and Materials

12 °C degrees Celsius

13 CAP Corrective Action Program

14 CFR Code of Federal Regulations

15 CISCC chloride-induced stress corrosion cracking

16 CLB current licensing basis

17 CoC certificate of compliance

18 CRIEPI Central Research Institute of Electric Power Industry

19 DE destructive examination

20 DOE U.S. Department of Energy

21 DSS dry storage system

22 EPRI Electric Power Research Institute

23 °F degrees Fahrenheit

24 FSAR Final Safety Analysis Report

25 GTCC greater-than-Class-C

26 GWd/MTU gigawatt days per metric ton uranium

27 HBU high burnup

28 HDRP HBU Dry Storage Cask Research and Development Project

29 INPO Institute of Nuclear Power Operations

30 ISFSI independent spent fuel storage installation

31 ISG Interim Staff Guidance

32 ITS important to safety

33 KJ kilojoule

34 LWR light water reactor

35 m meters

36 mol mole

37 N/A not applicable

38 NDE nondestructive examination

39 NEI Nuclear Energy Institute
x

1 NMSS Office of Nuclear Material Safety and Safeguards

2 NRC U.S. Nuclear Regulatory Commission

3 OMB Office of Management and Budget

4 PM NRC Project Manager

5 ppm parts per million

6 QA quality assurance

7 s second

8 SAR safety analysis report

9 SER safety evaluation report

10 SRP Standard Review Plan

11 SSC structure, system, and component 

12 TEPCO Tokyo Electric Power Company

13 TLAA time-limited aging analysis

14 TS technical specification

15 UFSAR Updated Final Safety Analysis Report

16
1

1 INTRODUCTION

2 This Standard Review Plan (SRP) is intended to provide guidance to the U.S. Nuclear 

3 Regulatory Commission (NRC) staff for the safety review of renewal applications for specific 

4 licenses of independent spent fuel storage installations (ISFSIs) and certificates of compliance 

5 (CoC) of dry storage systems (DSSs), as codified in Title 10 of the Code of Federal Regulations

6 (10 CFR) Part 72, “Licensing Requirements for the Independent Storage of Spent Nuclear Fuel 

7 and High-Level Radioactive Waste, and Reactor-Related Greater Than Class C Waste.” 

8 To renew a specific license, an applicant (i.e., the licensee) must submit a license renewal 

9 application at least two years before the expiration of the license, in accordance with the 

10 requirements of 10 CFR 72.42(b). To renew a CoC, an applicant (i.e., CoC holder, user, or 

11 user’s representative) must submit a renewal application at least 30 days before the expiration 

12 of the associated CoC in accordance with the requirements of 10 CFR 72.240(b). The NRC 

13 may renew a specific license or a CoC for a term not to exceed 40 years, in accordance with 

14 10 CFR 72.42(a), or 10 CFR 72.240(a), respectively. General licenses are not renewed. The 

15 general-license term is linked to the storage term of the CoC being used.

16 The NRC-approved DSSs listed in 10 CFR 72.214, “List of Approved Spent Fuel Storage 

17 Casks,” may be used by any 10 CFR Part 72 general licensee in accordance with 

18 10 CFR 72.212, “Conditions of General License Issued Under § 72.210.” If the CoC holder 

19 chooses not to apply for the renewal of a particular CoC or is no longer in business, a DSS user 

20 or user’s representative may apply for renewal of the CoC in place of the CoC holder.

21 Both the specific-license and the CoC renewal applications must contain revised technical 

22 requirements and operating conditions (fuel storage, surveillance and maintenance, and other 

23 requirements) for the ISFSI or DSS that address aging mechanisms and aging effects that could 

24 affect structures, systems, and components relied upon for the safe storage of spent fuel. 

25 Renewal applications must include (1) time-limited aging analyses, if applicable, that 

26 demonstrate that structures, systems, and components important to safety will continue to 

27 perform their intended function for the requested period of extended operation, and (2) aging 

28 management programs for management of issues associated with aging that could adversely 

29 affect structures, systems, and components important to safety. Applicants are encouraged to 

30 meet with the NRC staff at public pre-application meetings to discuss their proposed plans for 

31 the renewal application.

32 The technical review of the renewal application is primarily a materials engineering effort. The 

33 materials discipline should coordinate its review of the renewal application with other disciplines, 

34 such as the structural, health physics, thermal, criticality, and quality assurance disciplines, as 

35 appropriate, to help ensure that relevant aspects of the application and review have been 

36 addressed.

37 This SRP defines an acceptable method for the NRC staff to review and determine if the 

38 applicant demonstrates that the specific-licensed ISFSI or the DSS will continue to meet the 

39 applicable regulatory requirements of 10 CFR Part 72 during the period of extended operation. 

40 The reviewer should be aware that additional interim staff guidance may have been developed 

41 to clarify or address issues following the publication of this guidance. This SRP defines an 

42 acceptable method for satisfying the applicable regulatory requirements; it is not a regulatory 

43 requirement. An applicant may propose alternate means for satisfying the appropriate 
2

1 regulatory requirements. However, deviation from this guidance in whole or in part may result in 

2 an extended NRC staff review schedule.

3 The NRC staff may revise and update this SRP to clarify the content, correct errors, or 

4 incorporate modifications approved by the Division of Spent Fuel Management. Comments, 

5 suggestions for improvement, and notices of errors or omissions will be considered by, and 

6 should be sent to the Director, Division of Spent Fuel Management, Office of Nuclear Material 

7 Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.

8 The guidance document is not intended to be used for the review of other 10 CFR Part 72 

9 renewal applications, such as those for wet storage facilities or monitored retrievable storage 

10 installations.

11 Figure A is a flowchart of the specific-license and CoC renewal process.

12 Revision 1

13 Based on lessons learned from reviews of specific-license and CoC renewal applications and 

14 input received from the public and industry, the NRC staff proposed changes to NUREG-1927 

15 (Revision 0) to add greater detail and clarity. The staff held a public meeting on July 14–15, 

16 2014, to solicit stakeholder input on the staff’s considerations for revisions to the guidance. The 

17 staff subsequently took into consideration comments received and developed on the draft 

18 version issued for public comment. This revision of NUREG-1927 has focused on expanding 

19 reviewer guidance for evaluating aging management programs (AMPs) and ensuring these 

20 programs respond to operating experience to remain adequate throughout the period of 

21 extended operation. 

22 This revision to NUREG-1927 was developed in parallel with an ongoing effort by the Nuclear 

23 Energy Institute (NEI) to develop guidance for the industry in the preparation of applications for 

24 renewal of licenses and CoCs. NEI 14-03, Rev. 0, “Guidance for Operations-Based Aging 

25 Management for Dry Cask Storage” (ADAMS Accession No. ML14266A225), includes guidance 

26 on the continued evaluation of operating experience (see Section 3.6.1.10 of NUREG-1927, 

27 Rev. 1). One of the principles introduced in NEI 14-03 is the use of “tollgates” as a structured 

28 approach for assessing operating experience and data from applicable research and industry 

29 initiatives. In addition, NEI 14-03 describes an initiative to aggregate and disseminate aging30 related operating experience, research results, monitoring feedback, and inspection data 

31 between licensees. The staff provided comments on NEI 14-03, Rev. 0, to NEI on January 21, 

32 2015 (ADAMS Accession No. ML15013A201). The staff will continue to work with NEI as it 

33 continues to develop its guidance for proposed NRC endorsement. However, until a time when 

34 NEI 14-03 may be endorsed by NRC, Section 3.6.1.10 of NUREG-1927, Rev. 1 provides 

35 guidance to reviewers regarding information in NEI 14-03 that may be used or referenced by 

36 applicants for license or CoC renewals.

37
3

1

2 Figure A. Specific-License and CoC Renewal Process

3

1. General Information Review

• General Information (1.4.1)

• Financial Information (1.4.2)

• Environmental Report (1.4.3)

• Application Content (1.4.4)

2. Scoping Evaluation

• Scoping Process (2.4.1)

• SSCs within the Scope of Renewal (2.4.2)

• SSCs not within the Scope of Renewal (2.4.3)

3. Aging Management Review

• Identification of Materials and Environments (3.4.1.1)

• Identification of Aging Mechanisms and Effects (3.4.1.2)

• Aging Management Activities (3.4.1.3)

• Aging Management Review for Dry Storage System Internals (3.4.1.4)

3.5 Time-Limited Aging Analyses 3.6 Aging Management Programs
4

1 Standard Review Plan Structure

2 Each chapter of this SRP contains the following sections:

3 Review Objective: This section provides the purpose and scope of the review and establishes 

4 the major review objectives for the chapter. It also discusses the information needed, or 

5 coordination expected, from other NRC staff to complete the technical review.

6 Areas of Review: This section describes the structures, systems, and components; analyses,

7 data, or other information; and their sequence in the discussion of acceptance criteria.

8 Regulatory Requirements: This section summarizes the regulatory requirements in 

9 10 CFR Part 72 pertaining to the scoping process, aging management review, and aging 

10 management activities that include the time-limited aging analyses review. This list is not 

11 all-inclusive, since some parts of the regulations, such as 10 CFR Part 20, “Standards for 

12 Protection Against Radiation,” are assumed to apply to all chapters of the safety analysis report. 

13 The reviewer should read the complete language of the current version of 10 CFR Part 72 to 

14 determine the proper set of regulations for the section being reviewed.

15 Review Guidance: This section discusses the specific technical information that should be 

16 included in the application and reviewed for regulatory compliance. The review guidance can

17 be supplemented by interim staff guidance, NUREGs, etc.

18 Evaluation Findings: This section provides sample summary statements for evaluation findings 

19 to be incorporated into the safety evaluation report (SER) for each area of review. The reviewer 

20 prepares the evaluation findings based on the satisfaction of the regulatory requirements. The 

21 NRC publishes the findings in the SER.
5

1 1. GENERAL INFORMATION REVIEW

2 1.1 Review Objective

3 The purpose of the general information review is to ensure that the specific-license or certificate 

4 of compliance (CoC) renewal application meets the requirements listed in Section 1.3 below.

5 1.2 Areas of Review

6 Areas of review addressed in this chapter include the following:

7 • general information,

8 • financial information,

9 • environmental report, and

10 • application content.

11 Areas specifically excluded from the renewal review include the following: 

12 • structures, systems, and components (SSCs) associated with physical protection of the 

13 independent spent fuel storage installation (ISFSI) or dry storage system (DSS), 

14 pursuant to Title 10 of the Code of Federal Regulations (CFR) Part 72, “Licensing 

15 Requirements for the Independent Storage of Spent Nuclear Fuel and High-Level 

16 Radioactive Waste, and Reactor-Related Greater Than Class C Waste,” Subpart H, 

17 “Physical Protection,” and

18 • SSCs associated with the ISFSI emergency plan, pursuant to 10 CFR 72.32, 

19 “Emergency Plan.”

20 1.3 Regulatory Requirements

21 Table 1-1 presents a matrix that identifies the specific regulatory requirements pertaining to 

22 application content, general information about the specific licensee or CoC holder, financial 

23 information, and the environmental report. Additional regulatory requirements for the 

24 environmental report can be found in 10 CFR Part 51, “Environmental Protection Regulations 

25 for Domestic Licensing and Related Regulatory Functions.”
6

1 Table 1-1. Relationship of Regulations and General Information Review

Areas of Review

72.221

(a), (b), (c), (d)

72.221

(e)

72.30(c)1

Application Content ●

General Information ●

Financial 

Information ● ●

Environmental 

Report

2

Areas of Review

72.341 72.421 72.48 72.2402

(b), (c), (d)

Application Content ● ● ●

General Information

Financial 

Information

Environmental 

Report ●

1 3 These regulations apply only to specific license renewals per 10 CFR 72.13, “Applicability.” 2 4 These regulations apply only to CoC renewals per 10 CFR 72.13.

5 1.4 Review Guidance

6 This section provides review guidance for general information about the specific licensee and 

7 CoC holder (Section 1.4.1), financial information (Section 1.4.2), environmental report 

8 (Section 1.4.3), and application content (Section 1.4.4). This section also provides information 

9 on timely renewal (Section 1.4.5), amendment applications submitted during the renewal review 

10 or after the renewal is issued (Section 1.4.6) and license and CoC conditions (Section 1.4.7).

11 1.4.1 General Information 

12 The NRC project manager (PM) should ensure that the specific licensee has provided 

13 information pursuant to 10 CFR 72.22(a)–(d), including the specific licensee’s full name, 

14 address, and description of the business or occupation. Although 10 CFR 72.22(a)–(d) is not 

15 specifically identified as applying to CoC holders, the reviewer should ensure CoC holders 

16 submit the basic information cited in 10 CFR 72.22(a)–(d). If the specific licensee or CoC holder

17 is a partnership, the application should identify the name, citizenship, and address of each 

18 partner and the principal location at which the partnership does business. If the specific 

19 licensee or CoC holder is a corporation or an unincorporated association, the application should 

20 specify the State in which it is incorporated or organized and the principal location at which it 

21 does business, along with the names, addresses, and citizenships of its directors and principal 

22 officers. If the specific licensee or CoC holder is acting as an agent or representative of another 
7

1 person in filing the application, the application should provide the above information for the 

2 principal. If the specific licensee is the U.S. Department of Energy, then the application should 

3 specify the organization responsible for the construction and operation of the ISFSI and 

4 describe any delegations of authority and assignments of responsibilities.

5 1.4.2 Financial Information

6 In general, the PM should ensure that the renewal application for a specific license contains the 

7 necessary documentation regarding financial data, pursuant to 10 CFR 72.22(e), which shows

8 that the specific licensee can carry out the activities being sought for the requested duration. 

9 Information should state where the activity will be performed, the general plan for carrying out 

10 the activity, and the period of time for which the specific license is requested. The PM should 

11 ensure that the renewal application is based only on the approved design bases and does not 

12 include additional construction costs beyond the design bases. The application should identify 

13 other costs related to activities associated with managing aging mechanisms and effects, and it 

14 should identify ISFSI operating and decommissioning costs that have been revised from those 

15 specified in the original specific-license application for construction, operation, and 

16 decommissioning. In addition, the application should include a decommissioning funding plan 

17 that identifies any changes in decommissioning costs and the extent of contamination, pursuant 

18 to 10 CFR 72.30(c).

19 The scope of this standard review plan (SRP) does not include specific guidance for reviewing 

20 financial information. Financial reviews should be coordinated with financial reviewers in the 

21 Performance Assessment Branch of the Office of Nuclear Material Safety and Safeguards 

22 (NMSS) or the Office of Nuclear Reactor Regulation.

23 1.4.3 Environmental Report 

24 The PM should ensure that the specific-license renewal application contains an environmental 

25 report or supplement, as required by 10 CFR 51.60, “Environmental Report—Materials 

26 Licenses” and 10 CFR 72.34, “Environmental Report.” The supplemental report may be limited 

27 to incorporating by reference, updating or supplementing the information previously submitted to 

28 reflect any significant environmental changes, including those that may result from operating 

29 experience as related to environmental conditions, or a change in operations or proposed 

30 decommissioning activities.

31 The environmental report should also meet the general requirements of 10 CFR 51.45, 

32 “Environmental Report,” as applicable. As required by 10 CFR 51.45(c), the environmental 

33 report should contain sufficient data to aid the NRC in its development of an independent 

34 analysis.

35 The review of the environmental report should be coordinated with the Environmental Review 

36 Branch of NMSS.

37 1.4.4 Application Content

38 The reviewer should look for a map or guide to the renewal application to assist in its review, 

39 since the format may vary from that of a standard safety analysis report (SAR). The PM or 

40 reviewer should verify that the renewal application for both CoC and specific-license renewals 

41 contain all of the following sections:
8

1 • General Information,

2 • Scoping Evaluation,

3 • Aging Management Review (AMR),

4 • Time-Limited Aging Analyses (TLAAs),

5 • Aging Management Programs (AMPs),

6 • Information pertaining to granted exemptions and their implication to aging management,

7 • Changes or additions to technical specifications or to the specific license or CoC,

8 • Supplement to the final safety analysis report (FSAR), including:

9 o Scoping results

10 o Table of AMR results

11 o Summary of TLAAs and TLAAs’ conclusions, and

12 o Summary of AMPs

13

14 • A clear delineation of changes (on any SAR pages included with the renewal application) 

15 from either the SAR pages included with the last approved amendment (or initial) 

16 application, or the FSAR, whichever is most recent, and including:

17 o Annotations to show renewal-related changes and 

18 o Annotations to show 10 CFR 72.48 (“Changes, Tests, and Experiments”) changes 

19 since last biannual update as required by 10 CFR 72.48(d)(2).

20 For CoC renewal applications, the PM or reviewer should also verify that the renewal application 

21 includes:

22 • A description of the structure of the renewal application as it relates to the different 

23 amendments (i.e., for the CoC as a whole). This could be in the form of a guide to the 

24 renewal application to identify the sections or appendices applicable to each CoC 

25 amendment;

26 • A clear description of each amendment; that is, what each amendment changed from (or 

27 added to) the initial certificate (i.e., “amendment 0”), and/or what each amendment 

28 changed from (or added to) the previous amendments; and

29 • A clear description of the scope and content of the renewal application should be 

30 provided for each amendment. If there are different SSCs, materials, and environments

31 described in the different CoC amendments, changes to the following would need to be 

32 specified for each individual amendment:

33 o Scoping evaluation,

34 o Aging management review,

35 o Time limited aging analyses,

36 o Aging management programs,

37 o Changes or additions to technical specifications or to the CoC, and

38 o Supplement to the FSAR, including:
9

1 • Scoping results

2 • Table of AMR results

3 • Summary of TLAAs and TLAAs’ conclusions

4 • Summary of AMPs.

5 A CoC renewal includes the initial certificate (“amendment 0”) and all subsequent amendments. 

6 The subsequent amendments have the same termination date as the initial certificate. The CoC 

7 holder has the option to request that only certain (i.e., not all) amendments under a CoC be 

8 renewed. If amendments are not renewed, upon expiration, casks loaded under that 

9 amendment would need to be removed from service.

10 Drawings provided as part of the renewal application should be clear and legible. If information 

11 in drawings is unclear or illegible, the PM should ask the applicant for additional, larger or full12 size drawings. The reviewer should ensure that dimensions, materials, and other details on the 

13 drawings are consistent with those described in both the text of the renewal application and the 

14 FSAR supplement.

15 The reviewer should verify that the applicant has updated the appropriate drawings to reflect 

16 any changes made to the design of the SSCs through the application of 10 CFR 72.48. 

17 Reviewers should be familiar with NUREG/CR-5502, “Engineering Drawings for 10 CFR Part 71 

18 Package Approvals,” issued May 1998. Although NUREG/CR-5502 was developed for 

19 transportation packages, the criteria for drawings should be consistent for storage designs and 

20 therefore useful to the review process.

21 If the applicant provided drawings and descriptions as proprietary information in the application 

22 and requested them to be withheld from the public, the PM should review the request for 

23 withholding and ensure all the necessary information is available for the NRC to make a 

24 decision on the withholding request, in accordance with the requirements of 10 CFR 2.390, 

25 “Public Inspections, Exemptions, Requests for Withholding.”

26 The reviewer should ensure the specific-license or CoC renewal application does not include 

27 any changes to the design bases. Changes to the design bases must be requested through a 

28 separate amendment process.

29 1.4.5 Timely Renewal

30 To renew a specific license, an applicant must submit a renewal application at least 2 years 

31 before the expiration of the license in accordance with the requirements of 10 CFR 72.42(b). To 

32 renew a CoC, an applicant must submit a renewal application at least 30 days before the 

33 expiration of the associated CoC in accordance with the requirements of 10 CFR 72.240(b). 

34 When the applicant has submitted a timely application for renewal, the existing specific license 

35 or CoC will not expire until a final decision concerning the application for renewal has been 

36 made by the Commission. Therefore, any DSSs loaded during the initial license or CoC period 

37 may remain in service until the review of the renewal application is complete.

38 1.4.6 Amendment Applications Submitted During the Renewal Review or After the 

39 Renewal is Issued

40 By regulation, applicants must demonstrate that SSCs important to safety will continue to 

41 perform their intended function(s) for the requested period of extended operation as a part of the 
10

1 renewal request. For concurrent amendment and renewal applications, the amendment 

2 application should include a scoping evaluation and an AMR for that amendment to document 

3 the evaluation of the amendment’s SSCs (and associated subcomponents) for extended 

4 operation, or the renewal application should be supplemented to address the proposed 

5 amendment to document the evaluation of the amendment’s SSCs (and associated 

6 subcomponents) for extended operation. Any amendment application submitted after the 

7 renewal has been issued (post-renewal amendment applications) should include a scoping 

8 evaluation and an AMR for that amendment. 

9 For post-renewal amendment applications or concurrent amendment applications that include a 

10 scoping evaluation and an AMR, the amendment application should either: (1) show that the in11 scope SSCs (and associated subcomponents) described in the amendment are already 

12 encompassed in the TLAAs and/or AMPs included in the specific-license or CoC renewal 

13 application; or (2) include revised or new TLAAs and/or AMPs to address aging effects of any 

14 new in-scope SSCs (and associated subcomponents) proposed in the amendment application. 

15 The PM and technical reviewers should verify that the following information is included in the

16 amendment application (see also Section 1.4.4):

17 • A scoping evaluation that identifies any new SSCs (and associated subcomponents) 

18 included in the amendment request and discusses whether the SSCs (and associated 

19 subcomponents) are included or excluded from the scope of renewal, following the 

20 guidance in Chapter 2;

21 • An aging management review that identifies any applicable aging mechanisms and 

22 effects for the new SSCs (and associated subcomponents) within the scope of renewal; 

23 and 

24 • Changes to the FSAR, which should include: 

25 o Scoping results and identification of any new in-scope SSCs; 

26 o Revised table of AMR results; 

27 o Identification of the approved TLAAs (or the TLAAs included in the renewal 

28 application, for concurrent amendments) that address the new in-scope SSCs, or 

29 identification and a summary of any revised or new TLAAs and the TLAAs’ 

30 conclusions that support the amendment; and 

31 o Identification of the approved AMPs (or the AMPs included in the renewal 

32 application, for concurrent amendments) that encompass the new in-scope SSCs 

33 (and associated subcomponents), or a summary of proposed changes to approved 

34 AMPs or new AMPs that will apply to the new in-scope SSCs (and associated

35 subcomponents). 

36 For concurrent amendment and renewal applications, if there are different PMs assigned to the 

37 renewal review and the amendment review, the PMs and technical reviewers should coordinate 

38 across the reviews to ensure that renewal aspects are covered for the amendment. Note that, 

39 before proceeding with the review of an amendment submitted during the renewal review, the 

40 PMs should consider how each review may impact the other, and decide, in conjunction with 

41 Branch and Division management, whether to proceed with both reviews, or to delay one review 

42 until the other is complete. For additional guidance, refer to Regulatory Issue Summary (RIS) 

43 2004-20, “Lessons Learned from Review of 10 CFR Parts 71 and 72 Applications, (NRC 2004).”
11

1 The NRC staff may include a condition in the renewed license or CoC noting all future 

2 amendments would need to address aging management.

3 1.4.7 Conditions to Specific Licenses and CoCs in the Period of Extended Operation

4 In renewing a license or CoC, the staff should consider conditions necessary for issuance.

5 Several conditions are likely to be included in the license or CoC. 

6 Generally, the NRC staff will renew the license or CoC with a condition requiring the specific

7 licensee or CoC holder, respectively, to incorporate a renewal supplement into the FSAR, as 

8 submitted in the renewal application and revised through the review process (see Section 

9 1.4.4). The reviewer should recognize that the entirety of the AMP may not be incorporated into 

10 the FSAR, but may instead be documented by the reviewer as an appendix to the safety 

11 evaluation report (SER). The specific licensee will be required to continue to update the FSAR 

12 pursuant to the requirements in 10 CFR 72.70(b) and (c). The CoC holder will be required to 

13 continue to update the FSAR pursuant to the requirements in 72.248(a) and (b).

14 The NRC staff is also likely to renew a license or CoC with a condition requiring the applicant to 

15 update, revise, or create procedures for implementing the activities in the AMPs. These 

16 procedures will be subject to inspection to ensure they are maintained, implemented, and 

17 periodically updated to respond to operating experience and valid consensus codes and 

18 standards, while providing reasonable assurance that the pertinent SSCs maintain their 

19 intended function.

20 As the entirety of the AMP may not be included in the CoC or technical specifications, site

21 procedures for AMP implementation may later be changed. Therefore, additional conditions or 

22 technical specifications may be required in the specific license or CoC to ensure critical 

23 elements of the AMPs are effectively maintained. These conditions should be specific to 

24 information in the AMP described in the renewal application which staff relied upon to make the 

25 requisite safety findings of reasonable assurance of adequate protection of public health and 

26 safety, and the environment. 

27 The NRC staff may also include a condition in the renewed CoC to ensure that all future 

28 amendments address aging management. See Section 1.4.6 for guidance on post-renewal 

29 amendments. 

30 The NRC staff may modify the above conditions or include additional conditions, as needed, in 

31 the specific license or CoC being renewed. In addition, the applicant may also propose 

32 additional license or CoC conditions as part of its application if these strengthen the technical 

33 bases for the reviewer to reach reasonable assurance of adequate protection of public health 

34 and safety, and the environment.

35 1.5 Evaluation Findings

36 The reviewer prepares a summary statement and evaluation findings based on compliance with

37 the regulatory requirements in Section 1.3. The summary statement and evaluation findings 

38 should be similar in wording to the following example (the finding number is for convenience in 

39 cross-referencing within the SRP and SER):

40 The NRC staff has reviewed the general information provided in the renewal application 

41 and supplemental documentation. The NRC staff performed its review following the 
12

1 guidance provided in NUREG-1927, Rev. 1, “Standard Review Plan for Renewal of 

2 Specific Licenses and Certificates of Compliance for Dry Storage of Spent Nuclear Fuel,” 

3 and relevant interim staff guidance. Based on its review, the NRC staff finds:

4 F1.1 The information presented in the renewal application satisfies the 

5 requirements of 10 CFR 72.2, 72.22, 72.30, 72.34, 72.42, 72.48, and

6 72.240, as applicable. 

7 F1.2 The applicant has provided a tabulation of all supporting information and 

8 docketed material incorporated by reference, in compliance with 

9 10 CFR 72.42 or 10 CFR 72.240, as applicable. 

10

11
13

1 2. SCOPING EVALUATION

2 2.1 Review Objective

3 The scoping evaluation should identify the structures, systems, and components (SSCs) of the 

4 independent spent fuel storage installation (ISFSI) or dry storage system (DSS) that should be 

5 reviewed for aging mechanisms and effects.

6 2.2 Areas of Review

7 The reviewer should ensure that the applicant has included information about the following 

8 areas of review: 

9 • scoping process

10 • SSCs within the scope of specific-license or certificate of compliance (CoC) renewal

11 • SSCs not within the scope of specific-license or CoC renewal

12 2.3 Regulatory Requirements

13 The U.S. Nuclear Regulatory Commission (NRC) bases a specific-license or CoC renewal on 

14 the continuation of the approved design bases throughout the period of extended operation and 

15 on the maintenance of the intended functions of (a) SSCs important to safety and (b) SSCs 

16 which failure may affect a safety function. If new safety-related deficiencies in the design bases

17 are discovered, they must be addressed and rectified through the specific-license or CoC

18 amendment process. The renewal process cannot be used to facilitate approval of design 

19 changes.

20 Table 2-1 presents a matrix of regulatory requirements for renewal related to the scoping 

21 review.

22 Table 2-1 Relationship of Regulations and Scoping Review

Areas of Review 10 CFR Part 72 Regulations

72.3 72.241

(b), (c), 

(d)

72.241

(g)

72.421

(b)

Subpart F: 

Applicable Sections1

72.120, 72.122, 

72.124, 72.126, 

72.128

 72.2362

Applicable

Sections

Scoping Process ● ● ●

SSCs within the 

Scope of SpecificLicense or CoC 

Renewal

● ● ● ● ●

SSCs not within 

the Scope of 

Specific-License 

Renewal

● ● ●

1 23 These regulations apply only to specific-license renewals per 10 CFR 72.13. 2 24 These regulations apply only to CoC renewals per 10 CFR 72.13.
14

1

2 2.4 Review Guidance

3 This section provides review guidance for the scoping evaluation. Section 2.4.1 explains the 

4 scoping process, Section 2.4.2 discusses SSCs within the scope of renewal, while Section 2.4.3 

5 provides guidance for SSCs not within the scope of renewal.

6 2.4.1 Scoping Process 

7 Figure 2-1 provides a flowchart of the scoping evaluation process. The reviewer should ensure 

8 that the application provides documentation of the scoping process that includes the following:

9 • a description of the scoping process and methodology for the inclusion/exclusion of 

10 SSCs (and associated subcomponents) from the renewal scope,

11 • a list of the SSCs (and associated subcomponents) that are identified as within the 

12 scope of renewal, their intended function, and safety classification or basis for inclusion 

13 in the renewal scope,

14 • a list of the SSCs (and associated subcomponents) that are identified as not within the 

15 scope of renewal and basis for exclusion,

16 • a list of the sources of information used, and

17 • any discussion or drawings needed to clarify the process, SSC intended functions and 

18 safety classifications.

19 The application should include a list and description of reference sources used to support the 

20 scoping evaluation. Sources may include the following:

21 • SARs (including final SARs (FSARs), updated FSARs, and topical SARs),

22 • license or CoC,

23 • technical specifications,

24 • operating procedures,

25 • design-bases documents (e.g., calculations, specifications, design change documents),

26 • drawings,

27 • quality assurance plan or program,

28 • docketed correspondence,

29 • operating experience reports (site-specific or industry-wide, as applicable),

30 • 10 CFR 72.48 (“Changes, Tests, and Experiments”) reviews, 

31 • vendor information, or

32 • applicable NRC guidance.

33 The reviewer can refer to NUREG/CR-6407, “Classification of Transportation Packaging and 

34 Dry Spent Fuel Storage System Components According to Importance to Safety,” as a 

35 reference for classification of components as important to safety to determine the accuracy and 

36 completeness of the scoping evaluation. The reviewer should ensure that the scoping 

37 evaluation has evaluated all SSCs identified in the design-bases documents, and properly 
15

1 differentiated them as either within or not within the scope of renewal. In addition, the 

2 identification of SSCs and SSC subcomponents in the scoping evaluation should be consistent 

3 throughout the application. 
16

1

Is the SSC 

important to 

safety?

Could the failure 

of the SSC not Important 

to Safety impact a 

safety function?

SSC is not

within the scope of

renewal

SSC is 

within the scope of

renewal 

(see Figure 3-1)

Yes

No

No

Yes

Scoping evaluation

process for

specific license or 

CoC renewal

2

3 Figure 2-1 Flowchart of Scoping Evaluation Process

4
17

1 2.4.2 Structures, Systems, and Components within the Scope of Renewal 

2 The reviewer should verify that the SSCs (and associated subcomponents) within the scope of 

3 renewal fall into the following scoping categories:

4 (1) They are classified as important to safety, as they are relied on to do one of the following 

5 functions: 

6 i. Maintain the conditions required by the regulations, specific license, or CoC to 

7 store spent fuel safely;

8 ii. Prevent damage to the spent fuel during handling and storage; or

9 iii. Provide reasonable assurance that spent fuel can be received, handled, packaged, 

10 stored, and retrieved without undue risk to the health and safety of the public. 

11 These SSCs ensure that important safety functions are met for (1) confinement, 

12 (2) radiation shielding, (3) sub-criticality control, (4) heat-removal capability, (5) structural 

13 integrity, and (6) retrievability.

14 (2) They are classified as not important to safety but, according to the design bases, their 

15 failure could prevent fulfillment of a function that is important to safety.

16 The reviewer should verify that SSCs within the scope of renewal are screened to identify and 

17 describe the subcomponents with intended functions. The reviewer should recognize that SSC 

18 subcomponents may degrade by different modes, or have different criteria for evaluation from 

19 the overall component (i.e., different materials or environments). 

20 The scoping evaluation should clearly (i) define the intended function of each SSC 

21 subcomponent and (ii) differentiate SSC subcomponents per scoping criterions 1 or 2, as 

22 defined above. The reviewer should ensure that this information is tabulated or adequately 

23 described in the application. The reviewer should confirm that this information is 

24 comprehensive and accurate (i.e., SSC subcomponents are not missing from the scoping 

25 evaluation; SSC subcomponent naming is consistent with the design bases; intended functions 

26 are properly described) by comparing the results of the scoping evaluation to appropriate Final 

27 Safety Analysis Report (FSAR) drawings or tables.

28 2.4.2.1 Scoping of Dry Storage System Internals

29 The requirements in 10 CFR 72.122(h)(1) seek to ensure safe fuel storage and handling and to 

30 minimize post-operational safety problems with respect to removal of the fuel from storage. 

31 Pursuant to 72.122(h)(1), the spent fuel cladding must be protected during storage against 

32 degradation that leads to gross ruptures, or the spent fuel must be otherwise confined such that 

33 degradation of the spent fuel during storage will not pose operational safety problems with 

34 respect to its removal from storage. Regulations in 10 CFR 72.122(l) require that all storage 

35 systems must be designed to allow for ready retrieval of the spent fuel. The NRC staff has 

36 indicated in Interim Staff Guidance (ISG) 11, Rev. 3 (NRC 2003) that the spent fuel 

37 configuration is expected to be maintained as analyzed in the safety analyses for the dry 

38 storage system, provided certain acceptance criteria (regarding maximum fuel clad temperature 

39 and thermal cycling) are met, and the fuel is stored in a dry inert atmosphere (see 

40 Section 3.4.1.4). 
18

1 Traditional light water reactor spent nuclear fuel consists of fuel rods and assembly hardware. 

2 In turn, the fuel rods consist of uranium oxide pellets inside a cladding tube. The spent fuel 

3 cladding and assembly hardware provide structural support to ensure that the spent fuel is 

4 maintained in a known geometric configuration. Therefore, unless the intended functions of the 

5 dry storage system were analyzed with the fuel in a disrupted state, the condition of the fuel 

6 assembly and cladding are within the scope of renewal since their degradation may lead to a 

7 change in the analyzed fuel configuration. 

8 2.4.2.2 Scoping of Transfer Casks, Transporter Devices, and Reinforced Concrete Pads

9 The reviewer should be aware that transfer casks, transporter devices, and reinforced concrete 

10 pads may be classified as important to safety or safety-related (under 10 CFR Part 50) in the 

11 design bases of various ISFSIs or DSSs. The reviewer should review the FSAR to determine if 

12 these SSCs are within the scope of renewal.

13 2.4.3 Structures, Systems, and Components not within the Scope of Renewal 

14 For those SSCs (and associated subcomponents) excluded from the scope of renewal, the 

15 reviewer should verify that they do not meet either of the criterions described in Section 2.4.2. 

16 The reviewer should ensure that the applicant has properly justified any exclusions by 

17 referencing the design bases (i.e., FSAR description, drawings, or tables).

18 The following SSCs that are not important to safety may be excluded from the scope of renewal,

19 provided that they do not meet scoping category (2) in Section 2.4.2 above:

20 • equipment associated with cask loading and unloading, such as (1) welding and sealing 

21 equipment, (2) lifting rigs and slings, (3) vacuum-drying equipment, (4) portable radiation 

22 survey equipment, and (5) other tools, fittings, hoses, and gauges associated with cask 

23 loading and unloading,

24 • Instrumentation and other active components/systems (i.e. not passive or long-lived, but 

25 subject to a change in configuration or replacement based on a qualified life/service time 

26 period),

27 • SSCs associated with physical protection of the ISFSI, pursuant to 10 CFR Part 72, 

28 Subpart H, “Physical Protection,”

29 • SSCs associated with the ISFSI emergency plan, pursuant to 10 CFR 72.32,

30 “Emergency Plan,” and

31 • miscellaneous hardware that does not support or perform any function that is important

32 to safety.

33 2.5 Evaluation Findings

34 The reviewer prepares the summary statement and evaluation findings based on compliance 

35 with the regulatory requirements described in Section 2.3. The summary statement and 

36 evaluation findings should be similar in wording to the following example (the finding number is 

37 for convenience in cross-referencing within the Standard Review Plan (SRP) and safety 

38 evaluation report (SER)):

39 The NRC staff reviewed the scoping evaluation provided in the renewal application and 

40 supplemental documentation. The NRC staff performed its review following the 
19

1 guidance provided in NUREG-1927, Rev. 1, “Standard Review Plan for Specific 

2 Licenses and Certificates of Compliance for Dry Storage of Spent Nuclear Fuel,” and 

3 relevant ISGs. The NRC staff used the information provided in NUREG/CR-6407 

4 (“Classification of Transportation Packaging and Dry Spent Fuel Storage System 

5 Components According to Importance to Safety”) in its review as a reference for 

6 classification of components as important to safety to determine the accuracy and 

7 completeness of the scoping evaluation. Based on its review, the NRC staff finds:

8 F2.1 The applicant has identified all SSCs important to safety and SSCs whose

9 failure could prevent an SSC from fulfilling its safety function, per the 

10 requirements of 10 CFR 72.3, 10 CFR 72.24, 10 CFR 72.42, 10 CFR 72.120, 

11 10 CFR 72.122, 10 CFR 72.124, 10 CFR 72.126, 10 CFR 72.128 and 

12 10 CFR 72.236, as applicable.

13 F2.2 The justification for any SSC determined not to be within the scope of the 

14 renewal is adequate and acceptable.

15

21

1

2 3. AGING MANAGEMENT REVIEW

3 3.1 Review Objective

4 The purpose of the aging management review (AMR) is to assess the proposed aging 

5 management activities (AMAs) for structures, systems, and components (SSCs) determined to 

be within the scope of renewal. The AMR addresses aging mechanisms and effects1 6 that could 

7 adversely affect the ability of the SSCs (and associated subcomponents) from performing their

8 intended functions during the period of extended operation. The reviewer should verify that the 

9 renewal application includes specific information that clearly describes the AMR performed on 

10 SSCs within the scope of renewal.

11 3.2 Areas of Review

12 The reviewer should ensure that the AMR in the renewal application provides the following 

13 content with adequate technical bases: 

14 • identification of materials and environments for those SSCs and associated 

15 subcomponents determined to be within the scope of renewal,

16 • identification of aging mechanisms and effects requiring management, and

17 • identification of time-limited aging analyses (TLAAs), if applicable, and aging 

18 management programs (AMPs) for managing the effects of aging.

19 Figure 3-1 contains a flowchart for the AMR process. The final safety analysis report (FSAR)

20 and supporting documents related to the design are the primary documents that describe the 

21 safety classification, intended function, materials, and service environments for SSCs of 

22 independent spent fuel storage installations (ISFSIs), dry storage systems (DSSs), or both, 

23 identified to be within the scope for renewal (see Section 2.4.1).

24 The reviewer should consult applicable consensus codes and standards that provide additional 

25 guidance on the applicability of aging mechanisms and effects. The use of ambiguous 

26 terminology from any standard (e.g., “change in material properties”) should be properly defined 

27 or referenced in the application. Refer to Appendix A for assessing non-quantifiable terms.

28

29 The AMR should consider the duration of time between the fabrication of a system and its 

30 deployment in the ISFSI, which defines the start of the storage term (see Appendix F). The 

31 degradation of the system during that time period should be accounted for. For example, if a 

32 canister was stored for 5 years prior to use, the applicant should account for potential 

33 degradation of that canister during that 5-year period in any evaluation or analysis it conducts as 

34 part of the renewal application.

 1 In order to effectively manage an aging effect, it is necessary to determine the aging mechanisms that 

are potentially at work for a given material and environment application. Therefore, the aging 

management review process identifies both the aging effects and the associated aging mechanisms that 

cause them.
22

SSC or SSC subcomponent

within the scope 

of renewal (2.4.2)

Identification of 

materials and 

service environments

(3.4.1.1)

Determination of the 

AMA required to manage

the effects of aging 

(3.4.1.3)

Cont.

on next

page

Is the SSC or 

SSC subcomponent

subject to an 

aging mechanism 

or effect

(3.4.1.2)?

Document in

FSAR supplement. 

No further 

action necessary

No

Yes

1 2 Figure 3-1 Flowchart of AMR Process 
23

Is the TLAA 

reconfirmed for the 

renewal period?

TLAA confirmed and

documented in FSAR 

supplement.

No further action 

necessary

Yes

Yes

No Can TLAA 

adequately predict 

degradation associated 

with identified 

aging effect?

No

Action Required:

Modification of an AMP 

in Appendix B or

introduction of a

new AMP to be 

reviewed by the NRC

and documented in

FSAR supplement

TLAA AMP

Cont.

from

previous

page

1

2

3 Figure 3-1 Flowchart of AMR process (continued)

4
24

1 3.3 Regulatory Requirements

2 Title 10 of the Code of Federal Regulations (10 CFR) 72.42 and 10 CFR 72.240 provide the 

3 overarching requirements for aging management activities for renewal of specific licenses and 

4 CoCs. Table 3-1 presents a matrix of regulatory requirements that must continue to be met to 

5 ensure that the intended functions of SSCs of ISFSIs and DSSs are maintained during the 

6 period of extended operation. Other parts of 10 CFR Part 72 may also apply.

7 Table 3-1 Relationship of Regulations and Aging Management Reviews 

Areas of Review 10 CFR Part 72 Regulations

72.241

(d)

72.821

(d)

72.1041

(a)

72.1061

(b)

72.1201

(a),(d)

Aging Effects ● ● ● ●

Aging Management, Maintenance, 

or Surveillance Programs ●

TLAAs ● ● ● ●

8

Areas of Review 10 CFR Part 72 Regulations

72.1221

(a),(b),(c),(h)(1),

(h)(5),(l)

72.1221

(f),(h)(4),

(i)

72.124 72.126 72.1281

(a)

Aging Effects ● ● ●

Aging Management, Maintenance, 

or Surveillance Programs ● ● ●

TLAAs ● ● ● ● ●

9

Areas of Review 10 CFR Part 72 Regulations

72.158 72.162 72.164 72.168

(a)

72.170

Aging Effects ● ● ●

Aging Management, Maintenance, 

or Surveillance Programs ● ● ● ● ●

TLAAs ●

10
25

1 Table 3-1 Relationship of Regulations and Aging Management Reviews (continued)

Areas of Review 10 CFR Part 72 Regulations

72.172 72.2362

Applicable 

Sections

72.240(d)2

Aging Effects ● ●

Aging Management, Maintenance, 

or Surveillance Programs ● ● ●

TLAAs

1 2 These regulations apply only to specific-license renewals per 10 CFR 72.13. 2 3 These regulations apply only to CoC renewals per 10 CFR 72.13.

4 3.4 Materials, Service Environments, Aging Mechanisms and Effects, and 

5 Aging Management Activities

6 3.4.1 Review Guidance

7 This section provides review guidance for the aging management review. Section 3.4.1.1 

8 describes the identification of materials and their environments. Section 3.4.1.2 describes the 

9 identification of aging mechanisms and effects. Section 3.4.1.3 describes the review of aging 

10 management activities. Section 3.4.1.4 describes the aging management review for dry storage 

11 system internals.

12 3.4.1.1 Identification of Materials and Environments

13 The AMR process includes the identification of the materials of construction and the service 

14 environments for each SSC (or SSC subcomponent) within the scope of renewal. The 

15 identification of SSCs and SSC subcomponents in the AMR process should be consistent with 

16 the identification in the scoping evaluation. The reviewer should ensure that the renewal 

17 application has provided environmental data (and referenced the source of the data) such that 

18 the operating and service conditions of the SSCs can be determined. Environmental data may 

19 include:

20 • temperature, 

21 • wind, 

22 • relative humidity, 

23 • relevant atmospheric pollutants and deposits, 

24 • exposure to precipitation, 

25 • marine fog, salt, or water exposure, 

26 • radiation field (gamma and neutron), 

27 • the service environment (e.g., embedded, sheltered, or outdoor), and 

28 • gas compositions (e.g., external: air; internal: inert gas such as helium).
26

1 The reviewer should verify that the applicant considered the specific environment and material 

2 combinations in the DSS design for the evaluation of observed and potential aging mechanisms 

3 and effects that may lead to a loss of intended function. Particular attention should be paid to 

4 dissimilar metal combinations that may result in galvanic effects such as hydrogen uptake or 

5 galvanic corrosion. For sheltered environments that are in contact with the site atmosphere, the 

6 deposition and accumulation of atmospheric deposits should be evaluated. For example, 

7 chloride salt deposits that can promote accelerated corrosion of SSCs may be relevant in 

8 locations near salt water, adjacent to cooling towers, or in close proximity to roads that are 

9 treated with deicing salts.

10 3.4.1.2 Identification of Aging Mechanisms and Effects

11 The reviewer should ensure that the applicant has provided an analysis and documentation that 

12 identify aging mechanisms and effects pertinent to the SSCs determined to be within the scope 

13 of renewal. The AMR should include aging mechanisms and effects that could reasonably be 

14 expected to occur, as well as those that have actually occurred, based on industry and site15 specific operating experience and component testing. The reviewer should ensure that the CoC 

16 renewal evaluates all potential environments where the DSS may be used and provides 

17 applicable operating experience to justify the AMR conclusions.

18 The reviewer should review the applicant’s synopses of information used to identify applicable 

19 aging mechanisms and effects. Identification of applicable aging mechanisms and effects may 

20 be through review of: 

21 • site maintenance, repair, and modification records; 

22 • corrective action reports, including root cause evaluations; 

23 • lead system inspection results (see Appendix C); 

24 • maintenance and inspection records from ISFSI sites with similar SSC materials and 

25 operating environments; 

26 • industry records; 

27 • applicable operating experience outside the nuclear industry;

28 • applicable consensus codes and standards; 

29 • NRC reports; or

30 • other applicable guidance for determining if an aging mechanism or effect should be 

31 managed for the period of extended operation.

32 Examples of potential aging mechanisms and effects that may be identified by reviewing the 

33 sources of information cited above include: (1) cracking or loss of strength as a result of cement 

34 aggregate reactions in the concrete, (2) cracking or loss of material as a result of freeze-thaw 

35 degradation of the concrete (requires the presence of moisture combined with temperatures 

36 below freezing), (3) reinforcement corrosion and concrete cracking as a result of chloride 

37 ingress, (4) accelerated corrosion of steel structures and components and stress corrosion 

38 cracking of austenitic stainless steels as a result of atmospheric deposition of chloride salts. 

39 The reviewer should ensure that, if the applicant relies on operating experience, it is specifically 

40 applicable to the SSC subcomponent/material/environment, and is not just a compendium of 

41 references on similar topics.
27

1 The applicant is not required to take further action if an SSC is determined to be within the 

2 scope of renewal but is found to have no potential aging effects for the period of extended 

3 operation. The reviewer should verify that the applicant’s exclusion of an aging mechanism or 

4 effect is consistent with maintenance records, operational experience, and information obtained 

5 during lead system inspection(s). The reviewer should also ensure that the FSAR supplement or 

6 other application materials document the applicant’s determination of SSCs requiring no further 

7 review. 

8 3.4.1.3 Aging Management Activities

9 The reviewer should ensure that the applicant has identified those aging mechanisms and 

10 effects requiring either an AMP or TLAA. Figure 3-1 illustrates the process for handling those 

11 SSCs that are determined to be within the scope of renewal and subject to a potential aging 

12 effect. The AMR defines two methods for addressing potential aging mechanisms and effects: 

13 TLAA (Section 3.5) and AMP (Section 3.6). 

14 The NRC may condition the approval of a renewal on the requirements of a given AMP being 

15 met during the period of extended operation (see Section 1.4.7). The CoC user (general 

16 licensee) would ordinarily carry out the activities described in this AMP. Pursuant to 

17 10 CFR 72.212(b)(11) and 10 CFR 72.240(e), the NRC may make the AMP applicable to the 

18 general licensee by adding the appropriate condition(s) or technical specification(s) to the 

19 renewed CoC. Specific licenses may also be similarly conditioned (see Section 1.4.7).

20 3.4.1.4 Aging Management Review for Dry Storage System Internals

21 Since the DSS interior and cladding cannot be reasonably inspected, the reviewer should rely 

22 on lessons learned from NUREG/CR-6745, “Dry Cask Storage Characterization Project—

23 Phase 1; CASTOR V/21 Cask Opening and Examination,” (Bare et al., 2001), and 

24 NUREG/CR-6831, “Examination of Spent PWR Fuel Rods after 15 Years in Dry Storage,” 

25 (Einziger et al., 2003). This research demonstrated that low burnup fuel cladding and other 

26 cask internals had no deleterious effects after 15 years of storage. This research confirmed the 

27 basis for the guidance on creep deformation in Interim Staff Guidance (ISG) 11, “Cladding 

28 Considerations for the Transportation and Storage of Spent Fuel,” Revision 3, (NRC 2003). 

29 ISG-11 provides limits for temperature and stresses in the cladding to limit fuel reconfiguration. 

30 These research results suggest that degradation of low burnup fuel cladding and assembly 

31 hardware should not occur during the first renewal period, provided that the cask/canister 

32 internal environment is maintained. 

33 The reviewer should assess whether the applicant has considered the most recent revision of 

34 ISG-11 and research results in this area, especially with respect to high burnup (HBU) fuel. 

Research into fuel performance in storage is an ongoing effort2 35 . The reviewer should ensure 

36 that the applicant has monitored new research developments to ensure it has identified any 

37 new potential aging mechanisms and effects and provided new supporting data demonstrating 

38 HBU fuel performance during the period of extended operation. While NRC has confidence 

39 based on short-term testing (i.e., laboratory scale testing up to a few months) that there is 

40 no degradation of HBU fuel that would result in spent fuel being in an unanalyzed 

 2 For example, research programs at Argonne National Laboratory (for NRC and the U.S. Department of 

Energy (DOE), and Central Research Institute of Electric Power Industry) have studied hydride 

reorientation effects; Oak Ridge National Laboratory has also studied bending responses of the fuel.
28

1 configuration in the period of extended operation, there is no operational data to 

2 demonstrate this as was done in the aforementioned demonstration on low burnup fuel. 

3 Guidance for one acceptable approach to demonstrate the HBU fuel performance during 

4 the period of extended operation is provided in the “Example of a High Burnup Fuel 

5 Monitoring and Assessment Program” in Appendix B. This is a licensee program that 

6 monitors and assesses data and other information regarding HBU fuel performance, to 

7 confirm that the HBU fuel configuration is maintained during the period of extended 

8 operation. Guidance for determining if a surrogate demonstration program can provide the 

9 data to support a licensee’s HBU Fuel Monitoring and Assessment Program is given in 

10 Appendix D. Alternative approaches, including the use of test or research results and 

11 safety analyses for the fuel, may be used to demonstrate that the dry storage system 

12 intended functions continue to be met during the period of extended operation, as 

13 appropriately justified by an applicant.

14 3.4.2 Evaluation Findings

15 The reviewer prepares the summary statement and evaluation findings based on compliance 

16 with the regulatory requirements in Section 3.3. The summary statement and evaluation 

17 findings should be similar in wording to the following example (the finding number is for 

18 convenience in cross-referencing within the SRP and SER):

19 The NRC staff reviewed the aging management review provided in the renewal 

20 application and supplemental documentation. The NRC staff performed its review 

21 following the guidance provided in NUREG-1927, Rev. 1, “Standard Review Plan for 

22 Renewal of Specific Licenses and Certificates of Compliance of Dry Storage of Spent 

23 Nuclear Fuel,” and relevant ISGs. Based on its review, the NRC staff finds:

24 F3.1 The applicant’s AMR process to be comprehensive in identifying the 

25 materials of construction and associated operating environmental 

26 conditions for those SSCs within the scope of renewal and has provided a 

27 summary of the information in the renewal application and FSAR 

28 supplement.

29 F3.2 The applicant’s AMR process to be comprehensive in identifying all 

30 pertinent aging mechanisms and effects applicable to the SSCs within the 

31 scope of renewal and has provided a summary of the information in the 

32 renewal application and FSAR supplement.

33 3.5 Time-Limited Aging Analyses

34 TLAAs are calculations or analyses used to demonstrate that in-scope SSCs will maintain their 

35 intended function throughout an explicitly stated period of extended operation (e.g., 40 years). 

36 These calculations or analyses may be used to assess fatigue life (number of cycles to 

37 predicted failure), or time-limited life (operating timeframe until expected loss of intended 

38 function). TLAAs should account for environmental effects. Pursuant to 10 CFR 72.3, 

39 “Definitions,” TLAAs are those calculations and analyses meeting all six of the following criteria:

40 1. Involve SSCs important to safety within the scope of the specific-license renewal, as 

41 delineated in Subpart F of 10 CFR Part 72, or within the scope of the spent fuel storage 

42 CoC renewal, as delineated in Subpart L of 10 CFR Part 72, respectively;
29

1 2. Consider the effects of aging;

2 3. Involve time-limited assumptions defined by the current operating term;

3 4. Were determined to be relevant by the specific licensee or certificate holder in making a 

4 safety determination;

5 5. Involve conclusions or provide the basis of conclusions related to the capability of SSCs 

6 to perform their intended safety functions; and

7 6. Are contained or incorporated by reference in the design bases.

8 Pursuant to 10 CFR 72.42(a)(1) or 72.240(c)(2), the reviewer should ensure that the application 

9 includes a list of TLAAs. The NRC staff uses the FSAR and other documents where the design 

10 bases are detailed to perform the review and confirm that the applicant did not omit any TLAAs 

11 submitted as part of the approved design bases. The number and type of TLAAs vary 

12 depending on the design bases of the ISFSI or DSS. The reviewer should ensure that all six 

13 criteria set forth in 10 CFR 72.3 (and repeated in this section) are satisfied to conclude that a 

14 calculation or analysis is a TLAA.

15 The following examples illustrate analyses that are not TLAAs and need not be addressed 

16 under 10 CFR 72.42(a)(1) or 72.240(c)(2):

17 • Analysis with time-limited assumptions defined short of the initial license or CoC term, 

18 for example, an analysis for a component based on a service life that would not reach 

19 the end of the initial license or CoC term.

20 • Analysis not contained or incorporated by reference in the design bases. Although not 

21 TLAAs by definition, the reviewer should note that these analyses may be included in the 

22 renewal application to justify not including aging management activities for a particular 

23 SSC within the scope of renewal. 

24 3.5.1 Review Guidance

25 The reviewer should ensure that the applicant has appropriately identified TLAAs by applying 

26 the six criteria described below for SSCs within the scope of renewal:

27 1. Involve SSCs important to safety within the scope of the specific-license or CoC 

28 renewal. Chapter 2 of this SRP provides the reviewer guidance on the scoping 

29 methodology.

30 2. Consider the effects of aging. The effects of aging include but are not limited to loss of 

31 material, change in dimension, change in material properties, loss of strength, 

32 settlement, and cracking. The reviewer should ensure that any calculations or analyses 

33 relying on environmental susceptibility criteria are adequately supported by a valid 

34 technical basis, such as NRC endorsed criteria or operating experience. An AMP might 

35 be more applicable in these cases.

36 3. Involve time-limited assumptions defined by the current operating term. The defined 

37 operating term should be explicit in the analysis. Simply asserting that the SSC is 

38 designed for a DSS or ISFSI service life is not sufficient. Calculations, analyses, or 

39 testing that explicitly include a time limit should support the assertions.

40 4. Were determined to be relevant by the licensee or certificate holder in making a safety 

41 determination. Relevancy is a determination that the applicant makes based on a review 

42 of the information available. A calculation or analysis is relevant if it can be shown to 
30

1 have a direct bearing on the action taken as a result of the analysis performed. 

2 Analyses are also relevant if they provide the basis for a safety determination, and, in 

3 the absence of analyses, the applicant might have reached a different conclusion.

4 5. Involve conclusions or provide the basis of conclusions related to the capability of SSCs 

5 to perform their intended safety functions. The TLAA should provide conclusions or a 

6 basis for conclusions regarding the capability of the SSC to perform its intended function 

7 through the end of the period of extended operation. If the TLAA does not provide a 

8 conclusion supporting the capability of the SSC to perform its intended function through 

9 the end of the period of extended operation, then the TLAA is not confirmed, and the 

10 applicant should propose an AMP to address/manage the aging mechanism or effect on 

11 the SSC. Analyses that do not affect the intended functions of SSCs are not TLAAs. 

12 6. Are contained or incorporated by reference in the design bases. TLAAs should already 

13 be contained or incorporated by reference in the design-bases documents. Such 

14 documentation includes the (1) SAR, (2) technical specifications, (3) correspondence to 

15 and from the NRC, (4) quality assurance plan, and (5) topical reports included as 

16 references in the SAR. The reviewer should ensure that the applicant has provided any 

17 references cited in design-bases documents that may be needed to clarify the 

18 assumptions, methods or values used in TLAAs.

19 3.5.2 Evaluation Findings

20 The reviewer prepares the summary statement and evaluation finding based on compliance with 

21 the regulatory requirements in Section 3.3. The summary statement and evaluation finding 

22 should be similar in wording to the following example (the finding number is for convenience in 

23 cross-referencing within the SRP and SER):

24 The NRC staff reviewed the time-limited aging analyses (TLAAs) provided in the renewal 

25 application and supplemental documentation. The NRC staff performed its review 

26 following the guidance provided in NUREG-1927, Rev. 1, “Standard Review Plan for 

27 Renewal of Specific Licenses and Certificates of Compliance for Dry Storage of Spent 

28 Nuclear Fuel,” and relevant ISGs. The NRC staff verified that the TLAA assumptions, 

29 calculations, and analyses are adequate and bound the environment, and aging 

30 mechanism or aging effect for the pertinent SSCs. Based on its review, the NRC staff 

31 finds:

32 F3.3 The applicant identified all aging mechanisms and effects pertinent to 

33 SSCs within the scope of renewal that involve TLAAs. The methods and 

34 values of the input parameters for the applicant’s TLAAs are adequate. 

35 Therefore, the applicant’s TLAAs provide reasonable assurance that the 

36 SSCs will maintain their intended function(s) for the period of extended 

37 operation, require no further aging management activities, and meet the 

38 requirements in 10 CFR 72.42(a)(1) or 10 CFR 72.240(c)(2), as 

39 applicable.

40 3.6 Aging Management Programs

41 Aging management programs (AMPs) monitor and control the degradation of SSCs within the 

42 scope of renewal so that aging effects will not result in a loss of intended functions during the 

43 period of extended operation. An AMP includes all activities that are credited for managing 

44 aging mechanisms or effects for specific SSCs, including activities conducted during the initial 
31

1 storage period. An effective AMP prevents, mitigates, or detects the aging effects and provides 

2 for the prediction of the extent of the effects of aging and timely corrective actions before there 

3 is a loss of intended function.

4 Aging management programs should be informed, and enhanced when necessary, based on 

5 the ongoing review of both site-specific and industry-wide operating experience, including 

6 relevant international and non-nuclear operating experience. Operating experience provides 

7 direct confirmation of the effectiveness of an AMP and critical feedback for the need for 

8 improvement. As new knowledge and data become available from new analyses, experiments, 

9 and operating experience, licensees and CoC holders should revise existing AMPs (or pertinent 

10 procedures for AMP implementation) to address program improvements or aging issues.

11 3.6.1 Review Guidance

12 An AMP should contain the following 10 elements: 

13 1. Scope of Program, 

14 2. Preventive actions, 

15 3. Parameters monitored or inspected, 

16 4. Detection of aging effects, 

17 5. Monitoring and trending, 

18 6. Acceptance criteria,

19 7. Corrective actions, 

20 8. Confirmation process, 

21 9. Administrative controls, and 

22 10. Operating experience. 

23 Review of the AMPs should include an assessment of the 10 program elements to verify their 

24 technical adequacy. In general, the reviewer should examine the details of these 10 elements 

25 for managing the aging mechanisms and effects identified by the aging management review 

26 (AMR) process. The reviewer should recognize that an applicant may develop AMPs following 

27 a different format or style. For such reviews, the NRC staff should ensure that sufficient detail 

28 (i.e., supporting technical bases) is provided in the alternate format in comparison with the 10 

29 AMP elements of this guidance.

30 The reviewer should determine if the proposed AMP is adequate for managing the aging

31 mechanisms and effects of the SSCs identified by an AMR. The following sections provide 

32 specific guidance for the review of each element of an AMP.

33 3.6.1.1 Scope of Program

34 The scope of the program should list the specific SSCs and subcomponents covered by the 

35 AMP and the intended functions to be maintained. In addition, the element should state the 

36 specific materials, environments, and aging mechanisms and effects to be managed. The 

37 reviewer should verify that the scope defined for the AMP is clear and specific. 
32

1 3.6.1.2 Preventive Actions 

2 Preventive actions are used to prevent aging or mitigate the rates of aging for SSCs through the 

3 activities in the AMP. The reviewer should verify that these activities, if applicable, are 

4 described. For example, an applicant may cite a ground dewatering system to ensure control of 

5 long-term settlement of structures or the continuance of inspections to ensure that air inlet/outlet 

6 vents are not blocked. Some condition or performance monitoring programs do not rely on 

7 preventive actions and thus this information need not be provided.

8 The reviewer should ensure that any proposed preventive action will not result in an unintended 

9 consequence to the ability of an SSC to fulfill its intended function. For example, if the applicant 

10 has proposed to change a coating system in order to prevent loss of material due to corrosion, 

11 the reviewer should ensure that the applicant has verified coating compatibility to confirm that 

12 the proposed action will not compromise the intended function of the SSC.

13 3.6.1.3 Parameters Monitored or Inspected

14 This program element should identify the specific parameters that will be monitored or inspected 

15 and describe how those parameters will be capable of identifying degradation or potential 

16 degradation prior to a loss of intended function. The use of the parameters should be 

17 demonstrated to be capable of:

18 • monitoring the effectiveness of activities that prevent or mitigate aging (e.g., 

19 environmental controls),

20 • monitoring the performance of SSCs as an indirect indicator of degradation (e.g., 

21 radiation rate monitoring at the external surface of a cask), and

22 • detecting, through direct inspection, the presence and severity of conditions or 

23 discontinuities that may have an effect on the function of SSCs (e.g., nondestructive 

24 examination of a component surface).

25 The reviewer should ensure that this program element provides a clear link between the aging 

26 effects identified in the scope of the program and the parameters monitored or inspected.

27 3.6.1.4 Detection of Aging Effects

28 Detection of aging effects should occur before there is a loss of intended function for any SSC 

29 identified within the scope of the program. This element should include inspection and 

30 monitoring details, including method or technique (i.e., visual, volumetric, surface inspection), 

31 frequency, sample size, data collection, and timing of inspections to ensure timely detection of 

32 aging effects. In general, the information in this element describes the “when,” “where,” and 

33 “how” of the AMP (i.e., the specific aspects of the activities to collect data as part of the 

34 inspection or monitoring activities). 

35 The reviewer should ensure that the applicant has provided sufficient details on the following 

36 aspects of the inspection or monitoring activities:

37 • Method or technique: The method should be adequate and proven to be capable of 

38 evaluating the condition of the SSC against the acceptance criteria for the specific aging 

39 mechanism or effect being monitored or inspected (as defined in AMP Element 6). For 
33

1 example, the applicant should provide a valid technical basis that a particular instrument 

2 has sufficient resolution to identify a specific crack or defect dimension. 

3 • Frequency: The reviewer should ensure that the proposed intervals for inspection or 

4 monitoring are consistent with applicable site-specific or industry-wide operating 

5 experience. Inspections should have sufficient frequency to ensure that intended 

6 functions will be maintained until the next scheduled inspection.

7 • Sample size: The application should identify and justify the number of SSCs to be 

8 evaluated per inspection, including the extent of the inspection for each SSC (e.g., all 

9 accessible areas of five concrete overpacks in service). The reviewer should ensure the 

10 applicant has justified the use of a limited sample size (e.g., one cask per pad) with a 

11 technical basis, which should include applicable site-specific and industry-wide operating 

12 experience. The application should also define the areas that have been determined to 

13 be inaccessible or below-grade and propose how the condition of the inaccessible SSCs 

14 will be assessed. The reviewer should ensure that the scope of each inspection is 

15 properly defined for both accessible and inaccessible (including below-grade) areas. 

16 • Data collection: The application should reference any specific methods to be used for 

17 data acquisition, including any applicable consensus codes and standards. For 

18 example, the application may reference field evaluation guides for evaluating and 

19 documenting cracks in concrete (e.g., ACI 224.1R, ACI 201.1R). 

20 • Timing of inspections: The application may include results of a lead system inspection 

21 to serve as a baseline for the implementation of the AMP, which should be performed in 

22 accordance to Appendix C of this guidance. The reviewer should also consider any 

23 specific information on the proposed inspection schedule (e.g., time of the year) to 

24 support the effective detection of aging effects before a loss of intended function.

25 3.6.1.5 Monitoring and Trending

26 Monitoring and trending should provide for an evaluation of the extent of the effects of aging and 

27 the need for timely corrective or mitigative actions. This element describes how the data 

28 collected will be evaluated. This includes an evaluation of the results against the acceptance 

29 criteria and an evaluation regarding the rate of degradation in order to ensure that the timing of 

30 the next scheduled inspection will occur before a loss of intended function. For most cases, this 

31 element should have a baseline established prior to or at the beginning of the period of 

32 extended operation. The reviewer should determine if a baseline inspection is necessary to 

33 establish the parameters to be monitored and the trending analysis and, if so, whether the 

34 proposed baseline inspection is adequate (see Appendix C if the lead system inspection is 

35 being used to serve as a baseline inspection).

36 3.6.1.6 Acceptance Criteria 

37 The acceptance criteria, against which the need for corrective action will be evaluated, should 

38 ensure that the SSC intended functions and the approved design bases are maintained during 

39 the period of extended operation. The proposed acceptance criteria should be appropriately 

40 justified.

41 The acceptance criteria could be specific numerical values or could consist of a discussion of 

42 the process for calculating specific numerical values of conditional acceptance criteria to ensure 

43 that the design bases are maintained. The reviewer should ensure that the acceptance criteria:
34

1 • Include a quantitative basis (justifiable by operating experience, engineering analysis, 

2 consensus codes/standards),

3 • Avoid use of non-quantifiable phrases (e.g., significant, moderate, minor, little, slight, 

4 few), and

5 • Are achievable and actionable, that is, the method/technique is qualified to meet the 

6 stated quantitative criteria (e.g., sufficient resolution/sensitivity).

7 The acceptance criteria may be taken directly from the design bases information included in 

8 either the final safety analysis report (FSAR) or technical specifications. The acceptance criteria 

9 also may be established by methodologies provided in NRC-approved topical reports or 

10 appropriate codes and standards. 

11 3.6.1.7 Corrective Actions

12 Corrective actions are the measures to be taken when the acceptance criteria are not met. 

13 Timely corrective actions, including root cause determination and prevention of recurrence for 

14 significant conditions adverse to quality, are critical for maintaining the intended functions of the 

15 SSCs during the initial license or CoC term as well as the period of extended operation. 

16 Corrective actions should be described in adequate detail or referenced to source documents. 

17 An applicant may reference to the use of a Corrective Action Program (CAP), which is 

18 consistent with the quality assurance (QA) requirements in either 10 CFR Part 50, Appendix B, 

19 “Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants,” or 10 CFR 

20 Part 72, Subpart G, “Quality Assurance,” to capture and address aging effects identified in the 

21 period of extended operation. In this case, all conditions that do not meet the AMP acceptance 

22 criteria should be entered into the CAP. The QA Program ensures that corrective actions are 

23 completed within the specific or general licensee’s CAP and includes provisions to:

24 • Perform functionality assessments,

25 • Perform apparent cause evaluations and root cause evaluations,

26 • Address the extent of condition,

27 • Determine actions to prevent recurrence,

28 • Justify non-repairs, and

29 • Trend conditions.

30 The CAP should be able to respond to and adequately address any ISFSI or DSS aging issues. 

31 Also, the CAP’s response to addressing any ISFSI or DSS aging issues should include any 

32 specific corrective actions specified in the license or CoC renewal application.

33 The reviewer should review the corrective actions element with consideration of ISFSI site34 specific and industry-wide operating experience to ensure that the proposed corrective actions 

35 are adequate and effective. All applicable corrective actions should be discussed in the 

36 application.
35

1 3.6.1.8 Confirmation Process

2 This element of the program is intended to verify that preventive actions are adequate and that 

3 appropriate corrective actions have been completed and are effective. The confirmation 

4 process is commensurate with the specific or general licensee QA Program and is consistent 

5 with 10 CFR Part 72, Subpart G, or 10 CFR Part 50, Appendix B. The QA Program ensures 

6 that the confirmation process includes provisions to preclude repetition of significant conditions 

7 adverse to quality. The reviewer should ensure the confirmation process describes or 

8 references procedures to:

9 • Determine follow-up actions to verify effective implementation of corrective actions, and

10 • Monitor for adverse trends due to recurring or repetitive findings.

11 The reviewer should be aware that the effectiveness of prevention and mitigation programs 

12 should be verified periodically. For example, in managing corrosion of the canister, a mitigation 

13 program (coating) may be used to minimize susceptibility to corrosion. However, it also may be 

14 necessary to have a condition monitoring program (visual or other types of inspections) to verify 

15 that corrosion is being prevented or controlled to prevent a loss of intended function.

16 3.6.1.9 Administrative Controls

17 Administrative controls provide a formal review and approval process. Thus, any programs 

18 relied on to manage aging for ISFSI or DSS renewal must be administratively controlled and 

19 included in the FSAR supplement. The administrative controls are in accordance with the 

20 specific or general licensee QA Program and are consistent with 10 CFR Part 72, Subpart G or 

21 10 CFR Part 50, Appendix B, respectively. The QA Program ensures that the administrative 

22 controls include provisions that define:

23 • Instrument calibration and maintenance,

24 • Inspector requirements,

25 • Record retention requirements, and

26 • Document control.

27 The reviewer should ensure the administrative control element describes or references (a) the 

28 frequency and methods for reporting inspection results to the NRC, and (b) and the frequency 

29 for updating the AMP based on industry-wide operating experience.

30 3.6.1.10 Operating Experience

31 The reviewer should verify that operating experience element of the program provided by the 

32 applicant supports a determination that the effects of aging will be adequately managed so that 

33 the SSC intended functions will be maintained during the period of extended operation. 

34 Operating experience is useful in providing justification for the effectiveness of each AMP 

35 program element and critical feedback for enhancement. The reviewer should verify that any 

36 degradation in the referenced operating experience has been clearly identified as either age37 related or event-driven, with proper justification for that assessment. 

38 The reviewer should verify that the AMP references and evaluates applicable operating 

39 experience, including, but not necessarily limited to:
36

1 • Internal and industry-wide condition reports,

2 • Relevant international and non-nuclear operating experience,

3 • Licensee event reports,

4 • Vendor-issued safety bulletins,

5 • NRC Generic Communications, and

6 • Applicable industry-initiatives (e.g., Department of Energy or Electric Power Research 

7 Institute sponsored inspections).

8 The reviewer should verify that the AMP references the methods for capturing operating 

9 experience from other ISFSIs with similar in-scope SSCs. The reviewer should verify that the 

10 applicant: (1) references a specific repository to be used to obtain, aggregate, and enter site11 specific and industry-wide operating experience (e.g., Institute of Nuclear Power Operations

12 database), and (2) has discussed how it intends to provide timely reporting of operating 

13 experience to a repository.

14 The reviewer should consider operating experience of existing programs, including past 

15 corrective actions resulting in program enhancements or additional programs. A past failure 

16 would provide feedback from operating experience and should have resulted in appropriate 

17 program enhancements or new programs. This information can demonstrate where an existing 

18 program has been implemented correctly and where it has shortcomings in detecting 

19 degradation in a timely manner. This information should provide objective evidence to support 

20 or refute the conclusion that the effects of aging will be managed adequately so that the SSC 

21 intended functions will be maintained during the period of extended operation.

22 New AMPs that have yet to be implemented at an licensee’s facility do not have operating 

23 experience. However, there may be other relevant site-specific operating experience or generic 

24 operating experience in the industry that is relevant to the new AMP elements. Therefore, 

25 relevant operating experience applicable to new AMPs should be included in the discussion.

26 Learning AMPs

27 The reviewer should ensure that applicants commit to future reviews of site-specific and 

28 industry-wide operating experience, including relevant international and non-nuclear operating 

29 experience, to confirm the effectiveness of their AMPs or indicate a need to enhance or modify 

30 an AMP. The commitment to future reviews should ensure that, as knowledge and data 

31 become available from new analyses, experiments, and operating experience, the licensees 

32 and CoC holders will revise the existing AMPs (or pertinent procedures for AMP 

33 implementation) as necessary to address any deficiencies identified during the review of 

34 operating experience (see Figure 3-2).

35 If an applicant follows this approach, the reviewer should ensure that the description of the 

36 periodic assessments includes specific performance criteria (e.g., program-specific performance 

37 indicators for each of the 10 AMP elements) and proposed actions based on the assessment 

38 findings. The reviewer should also ensure that the timing of the assessments appropriately 

39 considers the rate of aging degradation and the anticipated availability of data from industry 

40 initiatives. The reviewer should consider the frequency, acceptance criteria, and proposed 

41 corrective actions for these assessments for the requisite finding of reasonable assurance.
37

1 Nuclear Energy Institute (NEI) 14-03, “Guidance for Operations-Based Aging Management for 

2 Dry Cask Storage,” Rev. 0, provides a proposed framework for learning AMPs through the use 

3 of “tollgates.” NEI 14-03 defines “tollgates” as periodic points within the period of extended 

4 operation when licensees would be required to document an aggregate safety assessment. 

5 Tollgates are described as an additional set of in-service assessments beyond the normal 

6 continual assessment of operating experience, research, monitoring, and inspections on DSS 

7 component performance that is part of normal ISFSI operations for licensees during the initial 

8 storage period as well as the period of extended operation. NEI 14-03 states that licensees will 

9 be obligated to comply with any tollgate license or CoC conditions approved as part of the 

10 license or CoC renewal. The reviewer should be aware that an applicant may reference the use 

11 of “tollgates” in the renewal application. The reviewer should (1) assess the applicant’s 

12 proposed periodic assessments of operating experience and other relevant data, and (2) make 

13 a determination regarding the ability of these assessments to ensure the continued 

14 effectiveness of AMPs. The reviewer should ensure that tollgates determined necessary to 

15 demonstrate the continued effectiveness of the AMPs are included as a condition of the 

16 renewed license or CoC.

17 NEI 14-03, Rev. 0, also describes a general framework for the aggregation and dissemination of 

18 operating experience across the industry through the use of an operating experience 

19 “clearinghouse.” Whether the applicant references the clearinghouse described in NEI 14-03 or 

20 proposes an alternative means to seek out operating experience, the reviewer should ensure 

21 that the application describes how industry-wide operating experience and results of industry 

22 initiatives will be accessed and utilized to ensure that AMPs are modified as appropriate.

23 As discussed in the Introduction, the staff will continue to work with NEI as it continues to 

24 develop NEI 14-03 for proposed NRC endorsement. 

25
38

1

Scope of the Program

Operating Experience

Acceptance

Criteria

Preventive Actions

Parameters Monitored or Inspected

Detection of Aging Effects

Monitoring and Trending

Corrective Actions

Confirmation Process

Yes

No

No

Yes

2

3 Figure 3-2: Learning AMP
39

1 3.6.2 Commencement of AMP(s) for CoC Renewals

2 An AMP for a renewed CoC commences at the end of the initial storage period for each loaded 

3 DSS (see Appendix F for discussion of storage terms, including an explanation of when storage 

4 begins). Activities in an AMP may start at different timeframes (e.g., an AMP can be 

5 implemented before the period of extended operation to capture baseline data and AMPs may 

6 have different frequencies of implementation). If the initial term of a CoC exceeds 20-years, the 

7 AMP may have been incorporated into the original CoC. In that case, the AMP commences at 

8 the time indicated in the CoC. Additional considerations for CoC renewals and general licensee 

9 implementation of AMPs are provided in Appendix E.

10 3.6.3 Implementation of AMP(s)

11

12 Generally, licensees should develop the infrastructure for AMP implementation (e.g., procure 

13 equipment or contracts, train personnel, or update, revise, or develop procedures for 

14 implementing AMP activities) before entering the period of extended operation. 

15

16 If a license or CoC is in the period of timely renewal (where the applicant submitted a renewal 

17 application within the time frames established in the regulations but the NRC has not yet made 

18 a final decision concerning the renewal application before the original license or certificate 

19 expiration date), development of the infrastructure for AMP implementation before the period of 

20 extended operation (and/or actual AMP implementation) may not be possible. In such cases, 

21 the reviewer should ensure that timing of implementation for each AMP is addressed in the 

22 application in a clear manner. Generally, development of the infrastructure for AMP 

23 implementation should be no later than one year from the date the NRC issues a renewed 

24 specific license or CoC. However, in some situations, shorter or longer AMP implementation 

25 periods may be appropriately justified. 

26 3.6.4 Evaluation Findings

27 The reviewer prepares the summary statement and evaluation finding based on compliance with

28 the regulatory requirements in Section 3.3. The summary statement and evaluation finding 

29 should be similar in wording to the following example (the finding number is for convenience in 

30 cross-referencing within the SRP and SER):

31 The NRC staff reviewed the aging management programs provided in the renewal 

32 application and supplemental documentation. The NRC staff performed its review 

33 following the guidance provided in NUREG-1927, Rev. 1, “Standard Review Plan for 

34 Renewal of Specific Licenses and Certificates of Compliance for Dry Storage of Spent 

35 Nuclear Fuel” and relevant ISGs. Based on its review, the NRC staff finds:

36 F3.4 The applicant has identified programs that provide reasonable assurance that 

37 aging effects will be managed effectively during the period of extended operation, in 

38 accordance with 10 CFR 72.42(a)(2) or 10 CFR 72.240(c)(3), as applicable.

39

41

1 4. CONSOLIDATED REFERENCES

2 Title 10 of the Code of Federal Regulations (10 CFR) Part 2. Code of Federal Regulations, Title 

3 10, Energy, Part 2, “Agency Rules of Practice and Procedure.” Washington, DC. 

4 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

5 Protection Against Radiation.” Washington, DC. 

6 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic Licensing of 

7 Production and Utilization Facilities.” Washington, DC. 

8 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

9 Protection Regulations for Domestic Licensing and Related Regulatory Functions.” 

10 Washington, DC. 

11 10 CFR Part 52. Code of Federal Regulations, Title 10, Energy, Part 52, “Licenses, 

12 Certifications, and Approvals for Nuclear Power Plants.” Washington, DC.

13 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

14 Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive 

15 Waste, and Reactor-Related Greater than Class C Waste.” Washington, DC.

16 76 FR 8872. February 16, 2011. “10 CFR Part 72, License and Certificate of Compliance

17 Terms, Final Rule.” Federal Register, U.S. Nuclear Regulatory Commission, Washington, DC. 

18 American Concrete Institute (ACI) 349.3R-02. 2010. “Evaluation of Existing Nuclear Safety19 Related Concrete Structures” (Reapp 2010). 

20 ACI 318-11. 2011. “Building Code Requirements for Structural Concrete.”

21 ACI 349-06. 2007. “Code Requirements for Nuclear Safety-Related Concrete Structures.”

22 ACI 201.1R-8. 2008. “Guide for Conducting a Visual Inspection of Concrete in Service.”

23 ACI 224.1R-07. 2007. “Causes, Evaluation, and Repair of Cracks in Concrete Structures.”

24 ACI 562-13. 2013. “Code Requirements for Evaluation, Repair, and Rehabilitation of Concrete 

25 Buildings.”

26 ACI 364.1R-07. 2007. “Guide for Evaluation of Concrete Structures before Rehabilitation.”

27 ACI 207.3R-94. 2008. “Practices for Evaluation of Concrete in Existing Massive Structures for 

28 Service Conditions.”

29 ACI 506R-05. 2005. “Guide to Shortcrete.”

30

31 American Society of Mechanical Engineers (ASME), “Boiler and Pressure Vessel Code Section 

32 XI - Rules for Inservice Inspection of Nuclear Power Plant Components,” New York, NY: ASME 

33 (2007).
42

1 ASME Code Section XI, Subsection IWL. 2013. “Requirements for Class CC Concrete 

2 Components of Light-Water-Cooled Plants.”

3 Bare, W.C, L.D. Torgerson. 2001. “Dry Cask Storage Characterization Project-Phase 1: 

4 CASTOR V/21 Cask Opening and Examination,” NUREG/CR-6745, Idaho National Engineering

5 and Environmental Lab, Idaho Falls, ID. Agencywide Documents Access and Management 

6 System (ADAMS) Accession No. ML013020363. 

7 Billone, M.C., T.A. Burtseva, and R.E. Einziger. 2013. “Ductile-to-Brittle Transition 

8 Temperature for High-Burnup Cladding Alloys Exposed to Simulated Drying-Storage 

9 Conditions,” in the Journal of Nuclear Materials, Volume 433, Issues 1–3, pages 431–448, 

10 February 2013.

11 Cumblidge, S.E., M.T. Anderson, S.R. Doctor. 2004. “An Assessment of Visual Testing,”

12 NUREG/CR-6860, Pacific Northwest National Laboratory, Richland, WA. ADAMS Accession 

13 No. ML043630040. 

14 Cumblidge, S.E, M.T. Anderson, S.R. Doctor, F.A. Simonen, A.J. Elliot. 2007. “A Study of 

15 Remote Visual Methods to Detect Cracking in Reactor Components,” NUREG/CR-6943, Pacific 

16 Northwest National Laboratory, Richland, WA. ADAMS Accession No. ML073110060.

17 Daum, R.S., S. Majumbdar, Y. Liu, and M.C. Billone. 2006. “Radial-hydride Embrittlement of 

18 High-burnup Zircaloy-4 Cladding”, Journal of Nuclear Science and Technology, Vol. 43, No. 9, 

19 p.1054, 2006.

20 Einziger, R.E., H. Tsai, M.C. Billone, B.A. Hilton. 2003. “Examination of Spent PWR Fuel Rods

21 after 15 Years in Dry Storage,” NUREG/CR-6831, Argonne National Laboratory, Argonne, IL. 

22 ADAMS Accession No. ML032731021.

23 EPRI/DOE. 2014. HBU Dry Storage Cask Research and Development Project Final 

24 Test Plan. February 27, 2014. DOE Contract No.: DE-NE-0000593. Accessible at 

25 http://www.energy.gov/sites/prod/files/2014/03/f8/HBUDry%20StrgeCaskRDfinalDemoT

26 estPlanRev9.pdf. 

27 Gorman, J., K. Fuhr, J. Broussard. 2014. “Literature Review of Environmental Conditions and 

28 Chloride-Induced Degradation Relevant to Stainless Steel Canisters in Dry Cask Storage 

29 Systems,” EPRI-3002002528, Palo Alto, CA: EPRI, 2014.

30 Hayashibara, H., M. Mayuzumi, Y. Mizutani, J. Tani. 2008. “Effect of Temperature and 

31 Humidity on Atmospheric Stress Corrosion Cracking of Stainless Steel,” Corrosion 2008, paper 

32 08492, Houston, TX: NACE International, 2008. 

33 He, X., Todd S. Mintz, Roberto Pabalan, Larry Miller, and Greg Oberson. 2014. “Assessment 

34 of Stress Corrosion Cracking Susceptibility for Austenitic Stainless Steels Exposed to 

35 Atmospheric Chloride and Non-Chloride Salts,” NUREG/CR-7170, U.S. Nuclear Regulatory 

36 Commission. ADAMS Accession No. ML14051A417.

37 Kamimura, K. 2010. “Integrity Criteria of Spent Fuel for Dry Storage in Japan” Proc. 

38 International Seminar on Interim Storage of Spent Fuel, ISSF 2010, Tokyo Nov 2010, page 

39 VI3-1.
43

1 Kosaki, A. 2008. “Evaluation Method of Corrosion Lifetime of Conventional Stainless Steel 

2 Canister under Oceanic Air Environment,” Nuclear Engineering and Design, Vol. 238, 

3 pp.1233-1240, 2008.

4 McConnell, J. W. Jr., A. L. Ayers, Jr., M. J. Tyacke. 1996. “Classification of Transportation 

5 Packaging and Dry Spent Fuel Storage System Components According to Importance to 

6 Safety,” NUREG/CR-6407, U.S. Nuclear Regulatory Commission. http://www.nrc.gov/reading7 rm/doc-collections/nuregs/contract/cr6407/cr6407.pdf.

8 Nuclear Energy Institute (NEI). 2014. “Guidance for Operations-Based Aging Management for 

9 Dry Cask Storage,” NEI 14-03, Rev. 0, ADAMS Accession No. ML14266A225.

10 U.S. Nuclear Regulatory Commission (NRC). 2000. “Standard Review Plan for Spent Fuel Dry 

11 Storage Facilities,” NUREG-1567, Revision 0. Washington, DC. ADAMS Accession No. 

12 ML003686776.

13 NRC. 2003. “Cladding Considerations for the Transportation and Storage of Spent Fuel,”

14 ISG-11, Revision 3. Washington, DC. ADAMS Accession No. ML033230335.

15 NRC. 2004. Regulatory Issue Summary (RIS) 2004-20, “Lessons Learned from Review of 

16 10 CFR Parts 71 and 72 Applications.” December 16, 2004. ADAMS Accession No. 

17 ML043510074.

18 NRC. 2010a. “Standard Review Plan for Spent Fuel Dry Storage Systems at a General 

19 License Facility,” NUREG-1536, Revision 1, Washington, DC. ADAMS Accession No. 

20 ML091060180.

21 NRC. 2010b. “Fuel Retrievability,” ISG-2, Revision 1. Washington, DC. ADAMS Accession 

22 No. ML100550861.

23 NRC. 2010c. “Generic Aging Lessons Learned (GALL) Report,” NUREG-1801, Revision 2, 

24 Washington, DC. ADAMS Accession No. ML103490041.

25 NRC. 2011. “Standard Review Plan for Renewal of Spent Fuel Dry Cask Storage System 

26 Licenses and Certificates of Compliance,” NUREG-1927, Revision 0, Washington, DC. ADAMS 

27 Accession No. ML111020115.

28 NRC. 2012a. Regulatory Issue Summary 2012-05: “Clarifying the Relationship Between 

29 10 CFR 72.212 and 10 CFR 72.48 Evaluations.” April 20, 2012. ADAMS Accession No.

30 ML113050537.

31 NRC. 2012b. Information Notice 2012-20: “Potential Chloride-Induced Stress Corrosion 

32 Cracking of Austenitic Stainless Steel and Maintenance of Dry Cask Storage System 

33 Containers.” November 14, 2012. ADAMS Accession No. ML12319A440.

34 NRC. 2014. “The Use of a Demonstration Program as a Surveillance Tool for Confirmation of 

35 Integrity for Continued Storage of HBU Fuel Beyond 20 Years,” ISG-24, Revision 0. 

36 Washington, DC. ADAMS Accession No. ML14058B166.

37 NRC. 2015. Letter from M. Lombard (NRC) to R. McCullum (NEI), dated January 21, 2015, 

38 Response to September 23, 2014, Nuclear Energy Institute Submittal: NEI 14-03, “Guidance for 
44

1 Operations-Based Aging Management for Dry Cask Storage,” Revision 0. ADAMS Accession 

2 No. ML15013A201. 

3 Sheaffer, M.K., G.R. Thomas, R.K. Dann, E.W. Russell. 1998. “Engineering Drawings for 

4 10 CFR Part 71 Package Approvals,” NUREG/CR-5502, Washington, DC. Accessible at: 

5 https://www.orau.org/ptp/pdf/5502.pdf.

6 Selby, G. 2005. “BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

7 Examination Guidelines,” EPRI 1011689, TR-105696-R8 (BWRVIP-03) Revision 8, Palo Alto, 

8 CA: EPRI 2005.

9 SEI/ASCE 11-99 (2000), “Guideline for Structural Condition Assessment of Existing Buildings.”

10 Tokiwai, M., H. Kimura, H. Kusanagi. 1985. “The Amount of Chlorine Contamination for 

11 Prevention of Stress Corrosion Cracking in Sensitized Type 304 Stainless Steel,” Corrosion 

12 Science, Vol. 25 Issue 8–9, pp. 837–844, 1985.

13 Waldrop, K., W. Bracey, K. Morris, C. Bryan, D. Enos. 2014. “Calvert Cliffs Stainless Steel Dry 

14 Storage Canister Inspection,” EPRI-1025209, EPRI, Palo Alto, CA, 2014. 
45

1 5. GLOSSARY

2 Accident condition: The extreme level of an event or condition, which has a specified 

3 resistance, limit of response, and requirement for a given level of continuing capability, which 

4 exceeds off-normal events or conditions. Accident conditions include both design-basis 

5 accidents and conditions caused by natural and manmade phenomena.

6 Aging effect: The manifestation of an aging mechanism (e.g., cracking, loss of fracture 

7 toughness, loss of material).

8 Aging management activity (AMA): An application of either the aging management program 

9 (AMP) or time-limited aging analyses (TLAAs) to provide reasonable assurance that the 

10 intended functions of structures, systems, and components (SSCs) of independent spent fuel 

11 storage installations (ISFSIs) and dry storage systems (DSSs) are maintained during the period

12 of extended operation.

13 Aging management program (AMP): A program conducted by the licensee or certificate of 

14 compliance (CoC) user for addressing aging effects that may include prevention, mitigation, 

15 condition monitoring, and performance monitoring. See Title 10 of the Code of Federal 

16 Regulations (10 CFR) 72.3, “Definitions.”

17 Aging management review (AMR): An assessment conducted by the licensee or certificate of 

18 compliance (CoC) holder that addresses aging mechanisms and effects that could adversely 

19 affect the ability of SSCs from performing their intended functions during the period of extended 

20 operation.

21 Aging mechanism: The degradation process for a given material and environment which results 

22 in an aging effect (e.g., freeze-thaw degradation, neutron irradiation, erosion).

23 Amendment of a License or CoC: An application for amendment of license or certificate of 

24 compliance (CoC) must be submitted whenever a holder of a specific license or CoC desires to 

25 amend the license or CoC (including a change to the license or CoC conditions). The 

26 application must fully describe the changes desired and the reasons for such changes, and 

27 following as far as applicable the form prescribed for original applications. See 10 CFR 72.56 

28 (“Application for Amendment of License”) and 72.244 (“Application for Amendment of a 

29 Certificate of Compliance”).

30 Burnup: The measure of thermal power produced in a specific amount of nuclear fuel through

31 fission, usually expressed in GWd/MTU (gigawatt days per metric ton uranium). 

32 Can for Damaged Fuel: A metal enclosure that is sized to confine one damaged spent fuel 

33 assembly. A fuel can for damaged spent fuel with damaged spent-fuel assembly contents must 

34 satisfy fuel-specific and system-related functions for undamaged spent nuclear fuel (SNF) 

35 required by the applicable regulations.

36 Canister (in a dry storage system for SNF): A metal cylinder that is sealed at both ends and 

37 may be used to perform the function of confinement. Typically, a separate overpack performs 

38 the radiological shielding and physical protection function. See NUREG-1536.

39 Certificate of compliance (CoC) (in a dry storage system for SNF): The certificate issued by the 

40 NRC that approves the design of a spent fuel storage cask in accordance with the provisions of 
46

1 10 CFR Part 72, “Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, 

2 High-Level Radioactive Waste, and Reactor-Related Greater than Class C Waste,” Subpart L, 

3 “Approval of Spent Fuel Storage Casks.” See 10 CFR 72.3.

4 Certificate of compliance holder (CoC holder): A person who has been issued a CoC by the 

5 U.S. Nuclear Regulatory Commission (NRC) for a spent fuel storage cask design under 10 CFR 

6 Part 72. See 10 CFR 72.3.

7 Certificate of compliance user (CoC user): The general licensee that has loaded, or plans to 

8 load, a dry storage system (DSS) in accordance with a CoC issued under 10 CFR Part 72.

9 Confinement (in a dry storage system for spent nuclear fuel): The ability to limit or prevent the 

10 release of radioactive substances into the environment. 

11 Confinement systems: Those systems, including ventilation, that act as barriers between areas 

12 containing radioactive substances and the environment. See 10 CFR 72.3.

13 Controlled area: The area immediately surrounding an ISFSI for which the licensee exercises 

14 authority over its use and within which it performs ISFSI operations. See 10 CFR 72.3.

15 Criticality: The condition wherein a system or medium is capable of sustaining a nuclear chain 

16 reaction.

17 Degradation: Any change in the properties of a material that adversely affects the performance 

18 of that material; adverse alteration. See NUREG-1536.

Design bases1 19 : Information that identifies the specific function(s) to be performed by SSCs 

20 (both important-to-safety and not important-to-safety) of a facility or of a spent fuel storage cask 

21 and the specific values or ranges of values chosen for controlling parameters as reference 

22 bounds for design. These values may be (1) restraints, derived from generally accepted “state23 of-the-art” practices for achieving functional goals, or (2) requirements, derived from analysis 

24 (based on calculation, experiments, or both) of the effects of a postulated event under which 

25 SSCs must meet their functional goals. See 10 CFR 72.3.

26 Dry storage system (DSS): A system that uses a cask or canister as a component in which to 

27 store spent nuclear fuel in a dry inert environment. A DSS provides confinement, radiological 

28 shielding, sub-criticality control, structural support, and passive cooling of its spent nuclear fuel 

29 during normal, off-normal, and accident conditions. 

30 Dry storage: The storage of spent nuclear fuel in an inert gas after removal of the water in the 

31 DSS cavity. 

32 General license: Authorizes the storage of spent fuel in an ISFSI at power reactor sites to 

33 persons (i.e., general licensee) authorized to possess or operate nuclear power reactors under 

34 10 CFR Part 50 (“Domestic Licensing of Production and Utilization Facilities”) or Part 52 

35 (“Licenses, Certifications, and Approvals for Nuclear Power Plants”). The general license is 

 1 The NRC has removed references to either “current licensing basis” (CLB) or “licensing basis”, and 

replaced with “design bases” in this guidance revision. Neither “current licensing basis” nor “licensing 

basis” is defined in 10 CFR Part 72. In addition, in the Statement of Considerations for the 2011 Part 72 

rulemaking change (NRC, 2011), the NRC stated “The NRC does not believe that it is appropriate for the 

CLB to be applied to cask CoC renewals, which are generic.” 
47

1 limited to (1) that spent fuel which the general licensee is authorized to possess at the site 

2 under the specific license for the site and (2) storage of spent fuel in casks approved under the 

3 provisions of 10 CFR Part 72. See 10 CFR 72.210 (“General License Issued”) and

4 72.212(a)(1)–(2). 

5 High burnup (HBU) fuel: Spent nuclear fuel with burnups generally exceeding 45 GWd/MTU. 

6 Horizontal storage module: A reinforced, heavy-walled concrete structure designed to store dry 

7 spent fuel canisters in a horizontal position at an independent spent fuel storage installation. 

8 The horizontal storage module provides physical protection of canisters and radiological 

9 shielding, while allowing passive cooling. 

10 Important to safety (ITS): See structures, systems, and components (SSCs) important to safety.

11 Independent spent fuel storage installation (ISFSI): A complex designed and constructed for 

12 the interim storage of spent nuclear fuel, solid reactor-related greater-than-Class-C (GTCC)

13 waste, and other radioactive materials associated with spent fuel and reactor-related GTCC 

14 waste storage. See 10 CFR 72.3. 

15 Inspection: The examination of an SSC, using a nondestructive testing technique, to determine 

16 its current condition and if there is any damage, defect, or degradation that could have an 

17 adverse effect on the function of that SSC. 

18 Intended function: A design-bases function defined as either (1) important to safety or 

19 (2) whose failure could impact a safety function. 

20 Interim Staff Guidance (ISG): Supplemental information that clarifies important aspects of 

21 regulatory requirements. An ISG provides review guidance to NRC staff in a timely manner until 

22 standard review plans are revised accordingly. See NUREG-1536.

23

24 Monitored Retrievable Storage Installation (MRS): A complex designed, constructed, and 

25 operated by DOE for the receipt, transfer, handling, packaging, possession, safeguarding, and 

26 storage of spent nuclear fuel aged for at least one year, solidified high-level radioactive waste 

27 resulting from civilian nuclear activities, and solid reactor-related GTCC waste, pending 

28 shipment to a HLW repository or other disposal. See 10 CFR 72.3.

29 Monitoring: Testing and data collection to determine the status of a DSS, ISFSI, or both, and to 

30 verify the continued efficacy of the system, on the basis of measurements of specified 

31 parameters, including temperature, radiation, functionality, and characteristics of components of 

32 the system. Monitoring could thus be described as those activities that periodically or 

33 continuously monitor performance as an indirect indicator of degradation or monitor the 

34 effectiveness of preventive measures (e.g., controlling water chemistry). With respect to 

35 radiation, per 10 CFR 20.1003 (“Definitions”), monitoring means the measurement of radiation 

36 levels, concentrations, surface area concentrations or quantities of radioactive material, and the 

37 use of the results of these measurements to evaluate potential exposures and doses. See 

38 NUREG-1567.

39 Normal events or conditions: The maximum level of an event or condition expected to routinely 

40 occur. The ISFSI is expected to remain fully functional and to experience no temporary or 

41 permanent degradation from normal operations, events, and conditions. Compares to “Design 

42 Event I” of ANSI/ANS 57.9. Events and conditions that exceed the levels associated with 
48

1 “normal” are considered to be, and to have the response allowed for, “off-normal” or “accident2 level” events and conditions. See NUREG-1567.

3 Off-normal events or conditions: The maximum level of an event or condition that, although not 

4 occurring regularly, can be expected to occur with moderate frequency and for which there is a 

5 corresponding maximum specified resistance, specified limit of response, or requirement for a 

6 specified level of continuing capability. Similar to “Design Event II” of ANSI/ANS 57.9. ISFSI 

7 SSCs are expected to experience off-normal events and conditions without permanent 

8 deformation or degradation of capability to perform their intended functions (although operations 

9 may be suspended or curtailed during off-normal conditions) over the full license period. Off10 normal is considered to include “anticipated occurrences” as used in 10 CFR Part 72. See 

11 NUREG-1536. 

12 Overpack: A heavy-walled concrete, metal, or combined concrete and metal structure designed 

13 to store spent fuel canisters at an ISFSI. The overpack provides physical protection of canisters 

14 and radiological shielding, while allowing passive cooling.

15 Radiation shielding: Barriers to radiation that are designed to meet the requirements of 

16 10 CFR 72.104(a), 10 CFR 72.106(b), and 10 CFR 72.128(a)(2).

17 Renewal of a License or CoC: A certificate holder may apply for renewal of the design of a 

18 spent fuel storage cask for a term not to exceed 40 years. In the event that the certificate holder 

19 does not apply for a cask design renewal, any licensee using a spent fuel storage cask, a 

20 representative of the licensee, or another certificate holder may apply for a renewal of that cask 

21 design for a term not to exceed 40 years. See 10 CFR 72.240, “Conditions for Spent Fuel 

22 Storage Cask Renewal.” Specific licenses may be renewed by the Commission at the 

23 expiration of the license term upon application by the licensee for a period not to exceed 40 

24 years. See 10 CFR 72.42, “Duration of License; Renewal.” 

25 Retrievability: Storage systems must be designed to allow ready retrieval of spent fuel, high26 level radioactive waste, and reactor-related GTCC waste for further processing or disposal. See 

27 72.122(l). Interim Staff Guidance (ISG) 2, Revision 1, provides guidance on the fuel 

28 retrievability, including ready retrieval.

29 Safety analysis report (SAR): The document that a CoC holder, specific licensee, an applicant 

30 for a CoC, or an applicant for a specific license supplies to the NRC for evaluation. For specific31 license renewals, the SAR must contain information required in 10 CFR 72.24, “Contents of 

32 Application; Technical Information.” For CoC renewals, the SAR must meet the requirements of 

33 10 CFR 72.240(b). The SAR provides references and drawings of the DSS, ISFSI, or both; 

34 details of construction; materials; and standards to which the SSC has been designed or 

35 fabricated. For clarification, SAR is a general term; while FSAR indicates the document that is 

36 updated within 90 days after the issuance of the license or CoC, reflecting any changes or 

37 applicant commitments developed during the license or CoC approval and/or hearing process. 

38 UFSAR indicates the SAR update that is required every 2 years. A specific licensee or CoC 

39 holder shall update the FSAR in accordance with 10 CFR 72.70 (“Safety Analysis Report 

40 Updating”) or 10 CFR 72.248, (“Safety Analysis Report Updating”) respectively.

41 Safety evaluation report (SER): The document that the NRC publishes at the completion of a 

42 licensing or certification review. The SER contains all of the NRC staff findings and conclusions 

43 from the licensing or certification review.
49

1 Safety function: A function defined as important to safety (ITS). The ITS functions that 

2 structures, systems, and components are designed to maintain include: 

3 • structural integrity,

4 • content temperature control (i.e., heat-removal capability),

5 • radiation shielding,

6 • confinement,

7 • sub-criticality control, and 

8 • retrievability. See NUREG-1536.

9 Service conditions: Conditions (e.g., time of service, temperatures, environmental conditions, 

10 radiation, and loading) that a component experiences during storage.

11 Specific license: A license for the receipt, handling, storage, and transfer of spent fuel, high12 level radioactive waste, or reactor-related GTCC waste that is issued to a named person (i.e., 

13 specific licensee) on an application filed pursuant to regulations in 10 CFR Part 72.

14 Spent fuel storage cask or cask: All the components and systems associated with the container 

15 in which spent fuel, or other radioactive materials associated with spent fuel, is stored at an 

16 ISFSI. See 10 CFR 72.3. 

17 Spent nuclear fuel or spent fuel: Nuclear fuel that has been withdrawn from a nuclear reactor 

18 after irradiation, has undergone at least a 1-year decay process since being used as a source of 

19 energy in a power reactor, and has not been chemically separated into its constituent elements 

20 by reprocessing. Spent fuel includes the special nuclear material, byproduct material, source 

21 material, and other radioactive materials associated with fuel assemblies. See 10 CFR 72.3.

22 Structures, systems, and components (SSCs) important to safety: See 10 CFR 72.3. Those 

23 features of the ISFSI and spent fuel storage cask whose functions are: 

24 • to maintain the conditions required to safely store spent fuel, high-level radioactive 

25 waste, or reactor-related GTCC waste,

26 • to prevent damage to the spent fuel, the high-level radioactive waste, or reactor-related 

27 GTCC waste container during handling and storage, or

28 • to provide reasonable assurance that spent fuel, high-level radioactive waste, or reactor29 related GTCC waste can be received, handled, packaged, stored, and retrieved without 

30 undue risk to the health and safety of the public. 

31 Time-limited aging analysis (TLAA): See 10 CFR 72.3. A licensee or CoC holder calculation or 

32 analysis that has all of the following attributes:

33 • involves SSCs important to safety within the scope of license or CoC renewal,

34 • considers the effects of aging,

35 • involves time-limited assumptions defined by the current operating term, for example, 

36 40 years,

37 • was determined to be relevant by the licensee or CoC holder in making a safety 

38 determination,

39 • involves conclusions or provides the basis for conclusions related to the capability of the 

40 SSCs to perform their intended safety functions, and
50

1 • is contained or incorporated by reference in the design bases.

2 Transfer cask: A shielded enclosure used to transfer the fuel canister between the spent fuel 

3 handling area and the overpack or storage module location.

4
1 APPENDIX A

2 NON-QUANTIFIABLE TERMS

A-1

1 Appendix A

2 Non-Quantifiable Terms

3 The following non-quantifiable terms, as well as others, may appear in the renewal application, 

4 safety analysis report (SAR), and updates to final SARs:

5 • large

6 • small

7 • slight

8 • slightly

9 • significant

10 • significance

11 • moderate

12 • moderately

13 • low 

14 • minor

15 • many

16 • few

17 • little

18 • routine

19 • some

20 • major

21 • undetectable

22 • visible

23 • measurable

24 • unchanged

25 • changed

26 • no loss of

27 Table A-1 may be used as guidance for the terms listed above, for additional consideration, or 

28 to provide quantitative measures or information.
A-2

1 Table A-1. Screening Criteria for Non-Quantifiable Terms

Terms Actions

Screened In

The term requires additional consideration if 

it is used for one of the following:

• characterizing an aging effect

(e.g., degradation, cracking, fatigue, 

corrosion, loss of material, change in 

material properties)

• providing important information about the 

operations, functions, or other 

characteristics of an in-scope SSC

• describing dose, environmental impact, or 

other hazard, such as combustible 

material or dust 

If the term screens in, one of 

the following must be 

provided:

• quantitative information,

if it is available

• additional descriptions

• definition of the meaning 

of the term

(e.g., “insignificant”

means the function of 

the SSC is not impaired)

Screened Out

The term is considered immaterial to the SAR 

and ISFSI UFSAR for one of the following 

reasons:

• The term is included in the title of 

reference document.

• The term is included in a quote.

• The term is explained by adjacent 

quantitative information (e.g., small: less 

than 20 percent).

• Use of the term is NOT related to any of 

the following:

 – in-scope SSCs per AMR results 

 – aging effect

 – dose, environment impact, or other 

hazard (e.g., combustible material)

• Use of the term does not provide important 

information. It is merely descriptive and the 

meaning of the statement is not changed if 

the term is deleted (e.g., the word “small” 

could be deleted from the following statement 

without altering the meaning: “Water in the

grapple ring is drained through a small hole”).

No action

2

3

4
1 APPENDIX B

2 EXAMPLES OF AGING MANAGEMENT PROGRAMS

B-1

1 Appendix B

2 Examples of Aging Management Programs

3 Appendix B contains example aging management programs (AMPs) for:

4 • localized corrosion and stress corrosion cracking of welded stainless steel dry storage 

5 canisters (Table B-1),

6 • reinforced concrete structures (Table B-2), and 

7 • high burnup (HBU) fuel monitoring and assessment program (Table B-3).

8 This appendix provides examples of acceptable AMPs for staff reference during review of 

9 renewal applications. 

10
B-2

1 Example AMP for Localized Corrosion and Stress Corrosion Cracking of

2 Welded Stainless Steel Dry Storage Canisters

3

4 Welded stainless steel canisters are used in the majority of the dry storage systems in the 

5 United States for spent nuclear fuel from commercial power reactors at both specific-licensed

6 and general-licensed independent spent fuel storage installations (ISFSIs). The welded 

7 stainless steel canisters are the primary confinement boundary during storage. While there are 

8 no known operational occurrences of aging or localized corrosion of welded stainless steel 

9 canisters, operational experience with nuclear reactors that were located close to an open 

10 ocean or bay has shown that pitting corrosion, crevice corrosion, and chloride-induced stress 

11 corrosion cracking (CISCC) can occur in welded stainless steel components as a result of 

12 atmospheric deposition and deliquescence of chloride-containing salts. Laboratory and natural 

13 exposure tests suggest that CISCC can occur with sufficient surface chloride concentrations 

14 and that, with those concentrations of chloride, crack propagation rates can be of engineering 

15 significance for welded stainless steel canisters during the period of extended operation.

16

17 Based on reactor operating experience as well as laboratory and field testing, localized 

18 corrosion and CISCC are potential aging mechanisms for welded stainless steel canisters.

19 Environments where chloride-containing salts may be deposited on welded stainless steel 

20 canisters include coastal locations near salt water and locations that are close to cooling towers 

21 or roads that are salted. To address these potential aging effects, an AMP for welded stainless 

22 steel canisters used in dry storage systems was developed by the NRC that relies on guidance 

23 from consensus codes and standards to perform in-service inspection of canisters to detect 

24 localized corrosion and CISCC. Elements of an NRC staff developed example AMP are 

25 described below.

26

27 Table B-1. Example AMP for Localized Corrosion and Stress Corrosion Cracking of Welded 

28 Stainless Steel Dry Storage Canisters

29

Element Description

1. Scope of Program Inspection of welded stainless steel dry storage canister confinement 

boundary external surfaces for atmospheric deposits, localized 

corrosion, and stress corrosion cracking. 

Examinations should be focused on the following areas:

• Canister fabrication welds and weld heat affected zones

• Closure welds and weld heat affected zones

• Areas of the canister to which temporary supports or 

attachments were attached by welding and subsequently 

removed

• Locations where a crevice is formed on the canister surface

• Horizontal (±30°) surfaces where deposit accumulation may 

accumulate at a faster rate compared to vertical surfaces

• Canister surfaces that are cold relative to the average surface 

temperature

• Canister surfaces with higher amounts of atmospheric deposits

2. Preventive 

Actions

None, AMP is for condition monitoring. However, dry storage system 

canister designs may include preventative actions such as fabrication 

procedures and surface modification methods to impart compressive 
B-3

Element Description

residual stresses on the canister welds and weld heat affected zones to 

reduce the potential for stress corrosion cracking. Preventative actions 

may also include the use of dry storage system canister confinement 

boundary materials that are resistant to localized corrosion and stress 

corrosion cracking. For such cases the preventative actions described 

should be supported with an analysis and data demonstrating the 

preventative actions are effective.

3. Parameters 

Monitored/ 

Inspected

Parameters monitored/inspected should include:

• Visual evidence of discontinuities and imperfections such as 

localized corrosion, including pitting corrosion, crevice corrosion 

and stress corrosion cracking of the canister welds and weld 

heat affected zones 

• Size and location of localized corrosion and stress corrosion 

cracks

• Appearance and location of deposits on the canister surfaces

4. Detection of 

Aging Effects

Visual inspection of deposits on the canister surfaces and to identify 

corrosion products that may be indicators of localized corrosion and 

stress corrosion cracking in the welds and weld heat affected zones. 

The ability to detect cracks on clean metal surfaces using visual 

examination methods is dependent on several factors and can be 

difficult for tight crack opening displacements (Cumblidge et al., 2004; 

2007). 

Volumetric inspection to characterize localized corrosion or stress 

corrosion cracking when evidence of localized attack is identified.

Visual Examination

Pitting and crevice corrosion that is open to the surface can potentially 

be detected by visual testing (ASME Section V, Table A-110). Because 

of the high neutron and gamma radiation fields near the surface of the 

stainless steel dry storage canisters, direct visual examination is not 

possible. Procedures for remote visual examination should be 

performance demonstrated; procedure attributes including equipment 

resolution, lighting requirements, etc., should reference applicable 

standards, such as ASME Section XI, Article IWA-2200 for VT-1 and 

VT-3 examinations (ASME, 2007) and BWRVIP-03 (Selby 2005) for 

EVT-1 examinations.

Volumetric Examination

Additional assessment is necessary for suspected areas of localized 

corrosion and/or stress corrosion cracking. In these cases, the severity 

of degradation must be assessed including the dimensions of the 

affected area and the depth of penetration with respect to the thickness 

of the canister. For accessible areas where adequate cleaning can be 

performed, remote visual inspection meeting the requirements for VT-1 
B-4

Element Description

Examination (ASME Section XI, IWA-2211) may be used to determine 

the type of degradation present (e.g., pitting corrosion or stress 

corrosion cracking) and the location of degradation. Examinations to 

characterize the extent and severity of localized corrosion and/or stress 

corrosion cracking should be conducted using surface and/or volumetric 

inspection techniques consistent with the requirements of ASME 

Section XI, IWB-2500 for category B-J components (ASME, 2007).

Sample Size

Minimum of one canister at each site. Preference should be given to 

the canisters with the greatest susceptibility for localized corrosion or 

SCC. Factors to be considered include older and colder canisters with 

the greatest potential for the accumulation and deliquescence of 

deposited salts that may promote localized corrosion and stress 

corrosion cracking, types of systems used at site, canister location with 

respect to potential sources of atmospheric deposits, system design,

and operational experience.

Data Collection

Documentation of the examination of the canister, location and 

appearance of deposits. Assessment of the suspect areas where 

corrosion products were observed as described in corrective actions.

Frequency

Once every 5 years

Timing of Inspections

Initial inspection must be completed prior to entering the period of 

extended operation at each site.

Alternative detection methods or techniques may be provided. For 

these cases:

• The method or technique should be adequate and proven to be 

capable of evaluating the condition of the external surface of the 

canister against the acceptance criteria for the detection of 

localized corrosion and stress corrosion cracking 

• The proposed intervals for inspection or monitoring are 

consistent with applicable site-specific or industry-wide 

operating experience and should have sufficient frequency to 

ensure that the confinement function will be maintained until the 

next scheduled inspection

• The data collection methods should be sufficient for evaluating 

localized corrosion and stress corrosion cracking and should 

reference specific methods to be used for data acquisition 
B-5

Element Description

including any applicable consensus codes and standards. 

5. Monitoring and 

Trending

Monitoring and trending methods are in accordance with ASME Section 

XI evaluation criteria. 

Monitoring and trending methods reference plans/procedures used to:

• Establish a baseline prior to or at the beginning of the period of 

extended operation

• Track trending of parameters or effects not corrected following a 

previous inspection including 

o The locations and size of any areas of localized 

corrosion and/or the stress corrosion cracking

o The disposition of canisters with identified aging effects 

and the results of supplemental canister inspections

Monitoring and trending should also include:

• The appearance of the canister, particularly at welds and in 

crevice locations, should be documented with images and video 

that will allow comparison in subsequent examinations

• Changes to the size and number of any rust colored stains as a 

result of iron contamination of the surface in subsequent 

inspections

6. Acceptance 

Criteria 

No indications of localized corrosion pits, etching, crevice corrosion, 

stress corrosion cracking, red-orange colored corrosion products 

emanating from crevice locations, or red-orange colored corrosion 

products in the vicinity of canister fabrication welds, closure welds, and 

welds associated with temporary attachments during canister 

fabrication.

Confirmed or suspected areas of crevice corrosion, pitting corrosion

and stress corrosion cracking must be assessed in accordance with 

acceptance standards identified in ASME Section XI, IWB-3514. Flaws 

exceeding the acceptance standards in IWB-3514.1 must be evaluated 

using the acceptance criteria identified in IWB-3640.

Indications Requiring Additional Evaluation

Although shop and handling procedures include controls to prevent iron 

contamination of the stainless steel surfaces, contamination does occur 

and is usually identified by rust-colored surface deposits. Iron 

contamination can exacerbate CISCC in stainless steels. In accessible 

locations, removal of the deposits and rust stains that reveal 

undamaged welds (i.e., absence of pits, crack, localized attack, or 

etching) and the original machining/grinding marks on the stainless 

steel base metal, including weld heat affected zones, may be used to 

confirm that localized corrosion or stress corrosion cracking have not 

been initiated. 
B-6

Element Description

Indications of interest that are subject to additional examination and 

disposition include: 

• Localized corrosion pits, crevice corrosion, stress corrosion

cracking, and etching [note that these indications may be 

covered by obstructions (i.e., crevices)]; deposits; or corrosion 

products 

• Discrete red-orange colored corrosion products that are 1 mm in 

diameter or larger especially those adjacent to fabrication welds,

closure welds, locations where temporary attachments may 

have been welded to and subsequently removed from the 

stainless steel dry storage canister, and the weld heat affected 

zones of these areas 

• Linear appearance of any color of corrosion products of any size 

parallel to or traversing fabrication welds, closure welds, 

locations where temporary attachments may have been welded 

to and subsequently removed from the stainless steel dry 

storage canister, and the weld heat affected zones of these 

areas 

• Red-orange colored corrosion products greater than 1 mm in 

diameter combined with deposit accumulations in any location of 

the stainless steel canister 

• Red-orange colored corrosion tubercles of any size

• Red-orange corrosion products present at the mouth of a 

crevice that includes a portion of the canister surface

Alternative acceptance criteria may be provided. For such cases, the 

acceptance criteria should:

• Include a quantitative basis (justifiable by operating experience, 

engineering analysis, consensus codes/standards),

• Avoid use of non-quantifiable phrases (e.g., significant, 

moderate, minor, little, slight, few), and

• Are achievable and clearly actionable, that is, the 

method/technique is qualified to meet the stated quantitative 

criteria (e.g., sufficient resolution/sensitivity).

7. Corrective 

Actions

The corrective actions are in accordance with the specific or general 

licensee Quality Assurance (QA) Program and consistent with 10 CFR 

Part 72, Subpart G, or 10 CFR Part 50, Appendix B. The QA Program 

ensures that corrective actions are completed within the specific or 

general licensee’s Corrective Action Program (CAP), and include 

provisions to:

• Perform functionality assessments,

• Perform apparent cause evaluations, and root

cause evaluations,

• Address the extent of condition,

• Determine actions to prevent recurrence; ensure justifications 
B-7

Element Description

for non-repairs,

• Trend conditions,

• Identify operating experience actions, including modification to 

the existing AMP (e.g., increased frequency), and

• Determine if the condition is reportable to the NRC (e.g., results 

in the loss of intended function).

Identification of localized corrosion and/or stress corrosion cracking 

also requires an expansion of the sample size to determine the extent 

of condition at the site. Canisters with confirmed localized corrosion or 

stress corrosion cracking must be evaluated for continued service. 

Canisters with localized corrosion or stress corrosion cracking that do 

not meet the prescribed evaluation criteria must be repaired or 

replaced.

Extent of Condition

Confirmation of localized corrosion and/or stress corrosion cracking 

requires inspection of additional canisters at the same location to 

determine the extent of condition. Priority for additional inspections 

should be to canisters with similar time in service and initial loading.

Disposition of Canisters with Aging Effects

For austenitic stainless steel canisters covered by an AMP that utilizes 

the inspection and acceptance criteria in ASME B&PV code Section XI 

for Class 1 piping system, the disposition of canisters should be 

commensurate with in-service inspection results:

• Canisters with no evidence of corrosion are permitted to remain 

in service and will continue to be inspected at 5-year intervals.

• Canisters with rust deposits that are determined to be a result of 

iron contamination but do not have evidence of localized 

corrosion or stress corrosion cracking are permitted to remain in 

service and will continue to be inspected at 5-year intervals. 

• Canisters that show evidence of localized corrosion and/or 

stress corrosion cracking that does not exceed the acceptance 

standards in IWB-3514.1 are permitted to remain in service and 

will be inspected at 5-year intervals. Sample size will be 

increased to assess 25 percent of canisters with similar time in 

service (± 5 years) or a minimum of one additional canister with 

a time in service closest to the original sample within one year of 

the completed in-service inspection date. Results of the initial 

inspection and the schedule for additional inspections will be 

reported to the NRC. In addition, the results for the additional 

in-service inspections will be reported to the NRC upon 

completion. 

• Canisters that show evidence of localized corrosion and/or 

stress corrosion cracking that exceeds the acceptance 

standards in IWB-3514.1 but meet the acceptance criteria 
B-8

Element Description

identified in IWB-3640 are permitted to remain in service and will 

be inspected at 3-year intervals. Sample size will be increased 

to assess 50 percent of canisters with similar time in service (± 5 

years) or a minimum of one additional canister with a time in 

service closest to the original sample within one year of the 

completed in-service inspection date. Results of the initial 

inspection and the schedule for additional inspections will be 

reported to the NRC. In addition, the results for the additional 

in-service inspections will be reported to the NRC upon 

completion.

• Canisters that show evidence of localized corrosion and/or 

stress corrosion cracking that exceeds acceptance criteria 

identified in IWB-3640 are not permitted to remain in service. 

Upon identification, the in-service inspection sample size will be 

increased to assess 100 percent of canisters with similar time in 

service (± 5 years) or a minimum of one additional canister with 

a time in service closest to the original sample within one year of 

the completed in-service inspection date. Results of the initial 

inspection, the schedule for mitigation either by repair or 

replacement and the schedule for additional inspections will be 

reported to the NRC. In addition, the results for the additional 

in-service inspections will be reported to the NRC upon 

completion.

8. Confirmation 

Process

The confirmation process will be commensurate with the specific or 

general licensee Quality Assurance (QA) Program and consistent with 

10 CFR Part 72, Subpart G or 10 CFR Part 50, Appendix B. The QA 

Program ensures that the confirmation process includes provisions to

preclude repetition of significant conditions adverse to quality.

The confirmation process describes or references procedures to:

• Determine follow-up actions to verify effective implementation of 

corrective actions 

• Monitor for adverse trends due to recurring or repetitive findings.

9. Administrative 

Controls

The specific or general licensee QA Program must be commensurate 

with 10 CFR Part 72, Subpart G or 10 CFR Part 50, Appendix B and 

specifically addresses: 

• Instrument calibration and maintenance,

• Inspector requirements

• Record retention requirements, and

• Document control.

The administrative controls describes or references: 

• Frequency/methods for reporting inspection results to the NRC

• Frequency for updating AMP based on industry-wide operational 

experience
B-9

Element Description

10. Operating 

Experience

The AMP references and evaluates applicable operating experience, 

including:

• Internal and industry-wide condition reports,

• Internal and industry-wide corrective action reports,

• Vendor-issued safety bulletins,

• NRC Information Notices, and

• Applicable DOE or industry initiatives (e.g., EPRI or DOE 

sponsored inspections).

The AMP clearly identifies any degradation in the referenced operating 

experience as either age-related or event-driven, with proper 

justification for that assessment. Past operating experience supports 

the adequacy of the proposed AMP, including the method/technique, 

acceptance criteria, and frequency of inspection.

The AMP references the methods for capturing operating experience 

from other ISFSIs with similar in-scope SSCs.

CISCC of austenitic stainless steels is a known degradation mechanism 

for aqueous environments; however, operational experience in aqueous 

environments is not directly applicable in assessing the potential for 

atmospheric CISCC for austenitic stainless steel dry storage canisters. 

Atmospheric CISCC of austenitic stainless steels has been reported in 

a range of industries including welded stainless steel components and 

piping in operating nuclear power plants.

Spent Fuel Storage

No cases of CISCC for stainless steel dry storage canisters have been 

reported. Inspections of dry storage canisters after 20 years in service 

have been conducted at a few independent spent fuel installation 

(ISFSI) sites. Details of the inspection conducted at the Calvert Cliffs 

nuclear power plant ISFSI are documented in a recent EPRI report 

(Waldrop et al., 2014). No evidence of localized corrosion was 

identified but some amount of chloride-containing salts were 

determined to be present and corrosion products believed to be related 

to iron contamination were identified. 

Operating Power Reactors

NRC Information Notice 2012-20 (NRC 2012b) documents previous 

cases of atmospheric CISCC of welded stainless steel piping systems 

and tanks at operating reactor locations. Atmospheric CISCC growth 

rates determined from operational experience at both domestic and 

foreign nuclear power plants including events at San Onofre, Turkey 

Point, St. Lucie, and Koeberg (South Africa) range from 3.6 x 10-12 m/s

to 2.9 x 10-11 m/s for components at ambient temperatures.
B-10

Element Description

Relevant Literature and Testing

Electric Power Research Institute (EPRI) has recently conducted a 

literature review of CISCC which summarizes the results of many 

previous laboratory investigations (Gorman et al., 2014).

The NRC has recently published the results of a completed 

investigation of CISCC testing of type 304, 304L and 316L stainless 

steel and welds (He et al., 2014). This study indicates that SCC was 

initiated at stresses just above the yield strength in tests conducted 

using 304 stainless steel C-ring specimens. Testing with U-bend 

specimens showed that CISCC was observed with the lowest simulated 

sea salt concentrations tested (100 mg salt/m2 or ~55 mg chloride/m2

) 

at temperatures of 52°C using a maximum absolute humidity of 

30 g/m3

, which is generally accepted as being near the maximum 

absolute humidity in a natural environment. 

Both laboratory and field investigations have been conducted by 

CRIEPI and TEPCO. This includes the early work by Tokiwai et al. 

(1985) who reported the critical surface chloride concentrations of 8 

mg/m2 for CISCC on sensitized 304 stainless steel. Kosaka (2008) 

reported crack growth rates of 9.6 x 10-12 m/s obtained in natural 

exposure tests on Miyakojima Island with type 304 base metals and 

welds, type 304L welds and type 316LN welds. Hayashibara et al. 

(2008) reported activation energy for crack growth in type 304 stainless 

steel of 5.6 to 9.4 kcal/mol (23 to 39 kJ/mol) based on testing 

conducted at temperatures of 50 to 80°C.

References American Society Of Mechanical Engineers, “Boiler and Pressure 

Vessel Code Section XI - Rules for Inservice Inspection of Nuclear 

Power Plant Components,” New York, NY: ASME (2007).

S.E. Cumblidge, M.T. Anderson, S.R. Doctor. 2004. “An Assessment 

of Visual Testing,” NUREG/CR-6860, Pacific Northwest National 

Laboratory, Richland, WA. Agencywide Documents Access and 

Management System (ADAMS) Accession No. ML043630040. 

S.E. Cumblidge, M.T. Anderson, S.R. Doctor, F.A. Simonen, A.J. Elliot.

2007. “A Study of Remote Visual Methods to Detect Cracking in 

Reactor Components,” NUREG/CR-6943, Pacific Northwest National 

Laboratory, Richland, WA. ADAMS Accession No. ML073110060.

J. Gorman, K. Fuhr, J. Broussard, “Literature Review of Environmental

Conditions and Chloride-Induced Degradation Relevant to Stainless 

Steel Canisters in Dry Cask Storage Systems,” EPRI-3002002528, Palo 

Alto, CA: EPRI, 2014.

H. Hayashibara, M. Mayuzumi, Y. Mizutani, J. Tani, “Effect of 

Temperature and Humidity on Atmospheric Stress Corrosion Cracking 

of Stainless Steel,” Corrosion 2008, paper 08492, Houston, TX: NACE 

International, 2008. 

A. Kosaki, “Evaluation Method of Corrosion Lifetime of Conventional 
B-11

Element Description

Stainless Steel Canister under Oceanic Air Environment,” Nuclear 

Engineering and Design, Vol. 238, pp.1233–1240, 2008

NRC. 2012b. Information Notice 2012-20: “Potential Chloride-Induced 

Stress Corrosion Cracking of Austenitic Stainless Steel and 

Maintenance of Dry Cask Storage System Containers.” November 14, 

2012. ADAMS Accession No. ML12319A440.

G. Selby, “BWR Vessel and Internals Project, Reactor Pressure Vessel 

and Internals Examination Guidelines,” EPRI 1011689, TR-105696-R8 

(BWRVIP-03) Revision 8, Palo Alto, CA: EPRI 2005.

M. Tokiwai, H. Kimura, H. Kusanagi, “The Amount of Chlorine 

Contamination for Prevention of Stress Corrosion Cracking in 

Sensitized Type 304 Stainless Steel,” Corrosion Science, Vol. 25 Issue 

8–9, pp. 837–844, 1985

X. He, T.S. Mintz, R. Pabalan, L. Miller, and G. Oberson, “Assessment 

of Stress Corrosion Cracking Susceptibility for Austenitic Stainless 

Steels Exposed to Atmospheric Chloride and Non-Chloride Salts,” 

NUREG/CR-7170, U.S. Nuclear Regulatory Commission, February 

2014, ADAMS Accession No. ML14051A417.

K. Waldrop, W. Bracey, K. Morris, C. Bryan, D. Enos, “Calvert Cliffs 

Stainless Steel Dry Storage Canister Inspection,” EPRI-1025209, EPRI, 

Palo Alto, CA, 2014.

1

2
B-12

1 Example AMP for Reinforced Concrete Structures

2

3 An example aging management program (AMP) for reinforced concrete structures is provided 

4 below. The AMP consists of condition monitoring, performance monitoring, mitigation and 

5 prevention activities. The program includes periodic visual inspections by personnel qualified to 

6 monitor reinforced concrete for applicable aging effects, such as those described in the 

7 American Concrete Institute guides (ACI) 349.3R-02, ACI 201.1R-08, and American National 

8 Standards Institute/American Society of Civil Engineers guidelines (ANSI/ASCE) 11-99. 

9 Identified aging effects are evaluated against acceptance criteria derived from the design bases 

10 or industry guides and standards, including ACI 349, ACI 318, ACI 349.3R-02 and the American 

11 Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI, 

12 Subsection IWL.

13

14 The program also includes periodic sampling and testing of groundwater and the need to 

15 assess the impact of any changes in its chemistry on below-grade concrete structures. 

16 Additional activities include radiation surveys to ensure the shielding functions of the concrete 

17 structure are maintained and daily inspections to ensure the air convection vents are not 

18 blocked (per the requirements of the approved design bases). The program also includes 

19 provisions where modifications may be appropriate for specific-license renewals.

20

21 Table B-2. Example AMP for Reinforced Concrete Structures

22

Element Description

1. Scope of Program The scope of the program includes the following aging management 

activities:

1. Visual inspection of above-grade (accessible, inaccessible) and 

below-grade (underground) concrete areas (See Element 4 for 

sample size and justification of areas to be inspected)

2. Groundwater chemistry program to manage below-grade 

(underground) aging mechanisms:

• Corrosion of embedded steel, and

• Chemical attack (chloride and sulfate induced degradation)

3. Radiation surveys to:

• Ensure compliance with 10 CFR 72.104, and

• Monitor performance of the concrete as a neutron shield at near 

system locations (i.e., determine dose uptrends); Validate 

modeling analyses and calculations described in the design 

bases.

The scope of the program provides means to address the following 

aging effects and mechanisms, as described in ACI 349.3R-02 and 

SEI/ASCE 11-99:

• Cracking or loss of material (spalling, scaling) due to 

freeze-thaw degradation,

• Cracking or loss of material (spalling, scaling) due to chemical 

attack (chloride, sulfate induced),

• Cracking and loss of strength due to cement aggregate 

reactions

• Cracking, loss of material, and loss of bond due to corrosion of 

embedded steel,
B-13

• Increase in porosity/permeability and loss of strength due to 

leaching of Ca(OH)2,

• Cracking and distortion due to long-term settlement,

• Cracking and reduction in strength due to high temperature 

dessication, and

• Cracking and reduction in strength due to gamma and neutron 

irradiation.

Calculations or analyses (time-limited aging analyses, when 

appropriate) may be used to demonstrate that aging effects due to 

irradiation and high temperature dessication do not require an AMP. 

More specifically, the renewal application may demonstrate that no part 

of the concrete exceeds:

• Critical cumulative fluences per ACI 349.3R-02: 1017

neutrons/m2; 1010 rad (gamma dose);

• Temperature limits per ACI 349-06: 150°F (general), 200°F

(localized).

Additional site-specific AMPs may be required for the following 

scenarios:

• A dewatering system is used to prevent long-term settlement

• The design bases includes embedded aluminum 

subcomponents without a protective insulating coating

• Protective coatings are relied upon to manage the effects of 

aging for a subcomponent

2. Preventive 

Actions Preventive actions include continuance of inspections to ensure that air 

inlet/outlet vents are not blocked and design temperature limits are not 

exceeded. These inspections would be part of the approved design 

bases and be continued for the sample size and inspection frequency 

identified in the respective technical specification.

Additional preventive actions are not required for structures designed 

and fabricated in accordance to ACI 318 or ACI 349, as specified in the 

design bases. Otherwise, a site-specific AMP may be required.

3. Parameters 

Monitored or 

Inspected

For visual inspections, the parameters monitored/inspected quantifies 

the following aging effects:

• Cracking,

• Material loss (spalling, scaling),

• Loss of bond, and

• Increased porosity/permeability.

The AMP references the following parameters for characterizing the 

above aging effects, as appropriate:

• Affected surface area,

• Geometry/depth of defect,

• Cracking, crazing, delaminations,

• Curling, settlements or deflections,
B-14

• Honeycombing, bug holes,

• Popouts and voids,

• Exposure of embedded steel,

• Staining/ evidence of corrosion, and

• Heavy dusting, efflorescence of any color.

The parameters evaluated are adequate for surface geometries that 

may support water ponding.

For the groundwater chemistry program, the parameters 

monitored/inspected include:

• Water pH and

• Concentration of chlorides and sulfates in the water.

For radiation surveys, the parameters monitored/inspected include 

gamma dose and/or neutron fluence.

4. Detection of 

Aging Effects

Method/technique

The method/technique achieves the acceptance criteria, as defined in 

AMP Element 6. An engineering justification or technical bases is 

provided, which references applicable consensus guides, codes and 

standards, and/or adequate calibration procedures to ensure the 

method or technique will provide reliable data.

For visual inspections, the method/technique is defined as:

• Visual method for above-grade (accessible) areas

• e.g., feeler gauges, crack comparators.

• Visual method for above-grade (inaccessible) and below-grade 

(underground) areas

• site-qualified system with valid sensitivity/resolution (e.g., 

video/ fiber optic camera).

For the groundwater chemistry program, the method/technique is 

defined as an adequate chemical analysis method.

For radiation surveys, the method/technique is defined as a calibrated 

detector with a valid energy range.

Frequency of Inspection

The proposed inspection schedule is commensurate with ACI 

349.3R-02. Alternative inspection frequencies provide a valid technical 

basis (engineering justification, operational experience data) for any 

deviation from ACI 349.3R-02.

For visual inspections, the frequency of inspection is defined as:

• For above-grade (accessible and inaccessible) areas: ≤ 5 years

• For below-grade (underground) areas: ≤ 10 years, and when 

excavated for any reason

• The use of opportunistic inspections in lieu of planned 

inspections per the above schedule provides a valid technical 
B-15

basis (engineering justification, operational experience data).

For the groundwater chemistry program, the frequency of monitoring is 

justified (e.g., quarterly, semiannual).

For radiation surveys, the frequency of monitoring is justified (e.g.,

quarterly).

Sample size

For visual inspections, the sample size includes all surface areas, or a 

justified sample size.

For visual inspections, the groundwater chemistry program, and 

radiation surveys, the sample size clearly identifies and justifies specific 

locations where inspection/monitoring will be conducted. The AMP 

properly defines accessible and inaccessible areas, and defines their 

respective sample size.

Data collection:

Data collection for visual inspections is commensurate with applicable

consensus codes/standards/guides:

• For example, ACI 224.1R for quantitative analysis (crack width, 

depth, extent), ACI 562, ACI 364.1R.

The AMP references an adequate clearinghouse for documenting 

inspection/monitoring operating experience.

Timing

The timing of the inspections includes the lead system inspection or 

general-licensee baseline inspection, performed per Appendix C of this 

NUREG, and at the frequency justified by the AMP.

5. Monitoring and 

Trending

Monitoring and trending methods are commensurate with defect 

evaluation guides and standards (e.g., ACI 201.1R, ACI 207.3R, ACI 

364.1R, ACI 562, or ACI 224.1R for crack evaluation).

Monitoring and trending methods reference plans/procedures used to:

• Establish a baseline prior to or at the beginning of the period of 

extended operation.

• Track trending of parameters or effects not corrected in a 

previous inspection, for example:

• Crack growth rates,

• Corrosion rates,

• Pore density/ affected areas, or

• Dose rates.

6. Acceptance 

Criteria For visual inspections, the acceptance criteria are commensurate with 

the 3-tier quantitative criteria in ACI 349.3R-02:

• Acceptance without further evaluation,

• Acceptance after review, and
B-16

• Acceptance requiring further evaluation.

The acceptance criteria clearly identify when a finding is to be entered 

in the Corrective Action Program (e.g., when Tier 2 acceptance per ACI 

349.3R-02 is exceeded).

For the groundwater chemistry program, the acceptance criteria are

commensurate with ASME Code Section XI, Subsection IWL, which 

states that an aggressive below-grade environment is defined as:

• pH < 5.5, chlorides > 500 ppm, or sulfates > 1500 ppm.

For radiation surveys, the acceptance criteria are justified and sufficient 

to ensure compliance with 10 CFR 72.104 and identify statistically 

significant uptrends in dose rates at or near overpack surfaces. The 

adequacy of the acceptance criteria considers design bases 

calculations documented in the FSAR. NUREG-1536 and NUREG1567 provide further guidance for the selection of cask or overpack 

locations at which dose rates are calculated per the initial ISFSI or DSS 

design review, which may be used for verification of shielding 

performance during the period of extended operation.

Alternative acceptance criteria may be provided. For such cases, the 

acceptance criteria:

• Include a quantitative basis (justifiable by operating experience, 

engineering analysis, consensus codes/standards),

• Avoid use of non-quantifiable phrases (e.g., significant, 

moderate, minor, little, slight, few), and

• Are achievable and clearly actionable, that is, the 

method/technique is qualified to meet the stated quantitative 

criteria (e.g., sufficient resolution/sensitivity).

7. Corrective 

Actions

The corrective actions are in accordance with the specific- or generallicensee QA Program and consistent with 10 CFR Part 72, Subpart G, 

or 10 CFR Part 50, Appendix B, respectively. The QA Program 

ensures that corrective actions are completed within the specific or 

general licensee’s CAP, and include provisions to:

• Perform functionality assessments,

• Perform apparent cause evaluations, and root 

cause evaluations,

• Address the extent of condition,

• Determine actions to prevent recurrence; ensure justifications 

for non-repairs,

• Trend conditions,

• Identify operating experience actions, including modification to 

the existing AMP (e.g., increased frequency), and

• Determine if the condition is reportable to the NRC (e.g., results 

in the loss of intended function).

The AMP references applicable concrete rehabilitation guides or 

standards, for example:

• Cracking: ACI 224.1R, ACI 562, ACI 364.1R, and ACI RAP 
B-17

Bulletins, or

• Spalling/scaling: ACI 562, ACI 364.1R, ACI 506R, and ACI RAP 

Bulletins.

8. Confirmation 

Process

The confirmation process is commensurate with the specific- or 

general-licensee QA Program and is consistent with 10 CFR Part 72,

Subpart G, or 10 CFR Part 50, Appendix B, respectively. The QA 

Program ensures that the confirmation process includes provisions to

preclude repetition of significant conditions adverse to quality.

The confirmation process describes or references procedures to:

• Determine follow-up actions to verify effective implementation of 

corrective actions, and

• Monitor for adverse trends due to recurring or repetitive findings.

9. Administrative 

Controls

The administrative controls are in accordance with the specific- or 

general-licensee QA Program and consistent with 10 CFR Part 72,

Subpart G, or 10 CFR Part 50, Appendix B, respectively. The QA 

Program ensures that the administrative controls include provisions that 

define:

• Instrument calibration and maintenance,

• Inspector requirements (commensurate with ACI 349.3R-02),

• Record retention requirements, and

• Document control.

The administrative controls describes or references: 

• Frequency/methods for reporting inspection results to the NRC, 

and

• Frequency for updating the AMP based on industry-wide 

operational experience.

10. Operating 

Experience

The AMP references and evaluates applicable operating experience, 

including:

• Internal and industry-wide condition reports,

• Internal and industry-wide corrective action reports,

• Vendor-issued safety bulletins,

• NRC Information Notices, and

• Applicable DOE or industry initiatives (e.g., EPRI or DOE 

sponsored inspections).

The AMP clearly identifies any degradation in the referenced operating 

experience as either age-related or event-driven, with proper 

justification for that assessment. Past operating experience supports 

the adequacy of the proposed AMP, including the method/technique, 

acceptance criteria, and frequency of inspection.

The AMP references the methods for capturing operating experience 

from other ISFSIs with similar in-scope SSCs.
B-18

References ACI 201.1R-08 (2008), “Guide for Conducting a Visual Inspection of 

Concrete in Service”

ACI 207.3R-94 (2008), “Practices for Evaluation of Concrete in Existing 

Massive Structures for Service Conditions”

ACI 224.1R-07 (2007), “Causes, Evaluation, and Repair of Cracks in 

Concrete Structures”

ACI 318-11 (2011), “Building Code Requirements for Structural 

Concrete”

ACI 349.3R-02 (2010), “Evaluation of Existing Nuclear Safety-Related 

Concrete Structures.”

ACI 349-06 (2007), “Code Requirements for Nuclear Safety-Related 

Concrete Structures”

ACI 364.1R-07 (2007), “Guide for Evaluation of Concrete Structures 

before Rehabilitation”

ACI 506R-05 (2005), “Guide to Shortcrete”

ACI 562-13 (2013), “Code Requirements for Evaluation, Repair, and 

Rehabilitation of Concrete Buildings”

ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWL 

(2013), “Requirements for Class CC Concrete Components of LightWater-Cooled Plants”

NRC. 2000. “Standard Review Plan for Spent Fuel Dry Storage 

Facilities,” NUREG-1567, Revision 0. Washington, DC. ADAMS 

Accession No. ML003686776.

NRC. 2010a. “Standard Review Plan for Spent Fuel Dry Storage 

Systems at a General License Facility,” NUREG-1536, Revision 1, 

Washington, DC. ADAMS Accession No. ML091060180.

NRC. 2010c. “Generic Aging Lessons Learned (GALL) Report,”

NUREG-1801, Revision 2, Washington, DC. ADAMS Accession No. 

ML103490041. 

SEI/ASCE 11-99 (2000), “Guideline for Structural Condition 

Assessment of Existing Buildings”

1

2
B-19

1 Example of a High Burnup Fuel Monitoring and Assessment Program

2

An example of a High Burnup (HBU) Fuel

1 3 Monitoring and Assessment Program is provided 

4 below. This is a licensee program that monitors and assesses data and other information 

5 regarding HBU fuel performance, to confirm that the design-bases HBU fuel configuration is 

6 maintained during the period of extended operation. This example HBU Monitoring and 

7 Assessment Program relies on a surrogate demonstration program to provide data on HBU fuel 

8 performance. Guidance for determining if a surrogate demonstration program can provide the 

9 data to support a licensee’s HBU Fuel Monitoring and Assessment Program is given in 

10 Appendix D. Although this example focuses on the use of a surrogate demonstration program, 

11 a licensee may use alternative approaches that are appropriately justified, including the use of 

12 test or research results and safety analyses for the fuel, to demonstrate that the dry storage 

13 system intended functions continue to be met during the period of extended operation.

14

15 The aging management review is not expected to identify any aging effects that could lead to 

16 fuel reconfiguration, as long as the HBU fuel is stored in a dry inert environment, temperature 

17 limits are maintained, and thermal cycling is limited (see Sections 2.4.2.1 and 3.4.1.4). Short18 term testing (i.e., laboratory scale testing up to a few months) and scientific analyses examining 

19 the performance of HBU fuel have provided a foundation for the technical basis that storage of 

20 HBU fuel in the period of extended operation may be performed safely and in compliance with 

21 regulations. However, there has been relatively little operating experience, to date, with dry 

22 storage of HBU fuel. 

23

24 Therefore, the purpose of a HBU Fuel Monitoring and Assessment Program is to monitor and 

25 assess data and other information regarding HBU fuel performance to confirm there is no 

26 degradation of HBU fuel that would result in an unanalyzed configuration during the period of 

27 extended operation. The following description of an example HBU Fuel Monitoring and 

28 Assessment Program presents the applicable information in a format using each element of an 

29 effective aging management program, to provide a framework for such a monitoring and 

30 assessment program.

31

32 Table B-3. Example of a High Burnup Fuel Monitoring and Assessment Program

33

Element Description

1. Scope of the 

Program

The scope of the program provides a description of: (1) the 

design-bases characteristics of the HBU fuel; (2) the surrogate 

demonstration program that will be used to provide data on the 

applicable design-bases HBU fuel performance; and (3) how the 

parameters of the surrogate demonstration program are applicable to 

the design-bases HBU fuel.

Aging effects will be determined for material/environment combinations 

per an alternative surrogate demonstration program meeting the 

guidance in Appendix D.

Example language to address this “scope of the program” element 

follows:

 1 Fuel assemblies with discharge burnup greater than 45 gigawatt-days per metric ton of uranium 

(GWd/MTU)
B-20

Element Description

Fuel stored in a [define cask/canister model] is limited to an assembly 

average burnup of [define design-bases limit] GWd/MTU. The cladding 

materials for the HBU fuel are [define types of cladding], and the fuel is 

stored in a dry helium environment. HBU fuel was first placed into dry 

storage in a [define cask/canister model] on [start date of storage term 

of first storage of HBU fuel].

The program relies on the joint Electric Power Research Institute 

(EPRI) and Department of Energy (DOE) “HBU Dry Storage Cask 

Research and Development Project” (HDRP) (EPRI 2014), conducted 

in accordance with the guidance in Appendix D, as a surrogate 

demonstration program that monitors the performance of HBU fuel in 

dry storage.

The HDRP is a program designed to collect data from a spent nuclear 

fuel storage system containing HBU fuel in a dry helium environment. 

The program entails loading and storing a AREVA TN-32 bolted lid cask 

(the “Research Project Cask”) at Dominion Virginia Power’s North Anna 

Power Station with intact HBU fuel (of nominal burnups ranging 

between 53 GWd/MTU and 58 GWd/MTU). The fuel to be used in the 

program include four kinds of cladding (Zircaloy-4, low-tin Zircaloy-4, 

ZirloTM, and M5TM). The Research Project Cask is to be licensed to the 

temperature limits contained in Interim Staff Guidance (ISG) 11, Rev. 3 

(NRC 2003), and loaded such that the fuel cladding temperature is as 

close to the limit as practicable. [If an alternative surrogate 

demonstration program is used, provide a description of the program.]

The parameters of the surrogate demonstration program are applicable 

to the design-bases HBU fuel, as the: (1) maximum burnup of the 

design-bases HBU fuel [define value] is less than the burnup of the fuel 

in the surrogate demonstration program [define value]; (2) the cladding 

type of the design-bases HBU fuel [define type] is the same as the 

surrogate demonstration program [define type]; and (3) the 

temperatures in the surrogate demonstration program [define values]

bound the design-bases temperature/heat load of the loaded systems 

[define values]. 

2. Preventive 

Actions

There are no specific preventive actions associated with this HBU Fuel 

Monitoring and Assessment Program. However, the applicant should 

discuss the design-bases characteristics of the licensed/certified dry 

storage system, in terms of initial cask loading operations, to show the 

HBU fuel is stored in a dry inert environment.

Example language follows:

During the initial loading operations of the cask/canister, the design and 

ISFSI Technical specifications (TS) require that the fuel be stored in a 

dry inert environment. TS [name and number] demonstrates that the 

cask/canister cavity is dry by maintaining a cavity absolute pressure 

less than or equal to [value] for a [time period] with the cask/canister 
B-21

Element Description

isolated from the vacuum pump. TS [name and number], requires that 

the cask/canister then be backfilled with helium. These two TS 

requirements ensure that the HBU fuel is stored in an inert environment 

thus preventing cladding degradation due to oxidation mechanisms. TS 

[name and number] also requires that the helium environment be 

established within [time] hours of commencing cask/canister draining. 

The cask/canister is loaded in accordance with the criteria of ISG-11. 

3. Parameters 

Monitored or 

Inspected

The applicant identifies the parameters monitored and inspected in a 

surrogate demonstration program that are applicable to its particular 

design-bases HBU fuel and describes how this meets the guidance of 

Appendix D.

4. Detection of 

Aging Effects

The applicant identifies the detection of aging effects in a surrogate 

demonstration program that are applicable to its particular design-bases 

HBU fuel and describes how this meets the guidance of Appendix D.

5. Monitoring and 

Trending

As information/data from a surrogate demonstration program or from 

other sources (such as testing or research results and scientific 

analyses) becomes available, the licensee will monitor, evaluate, and 

trend the information via its operating experience program and/or the 

Corrective Action Program (CAP) to determine what actions should be 

taken. 

The licensee will evaluate the information/data from a surrogate 

demonstration program or from other sources to determine whether the 

acceptance criteria in Element 6 are met. 

• If all of the acceptance criteria are met, no further assessment is 

needed. 

• If any of the acceptance criteria are not met, the licensee must 

conduct additional assessments and implement appropriate 

corrective actions (see Element 7). 

Formal evaluations of the aggregate information from a surrogate 

demonstration program and other available domestic or international 

operating experience (including data from monitoring and inspection 

programs, NRC-generated communications, and other information) will 

be performed at specific points in time during the period of extended 

operation, as delineated in Table B-4 below. 

6. Acceptance 

Criteria

The High Burnup Fuel Monitoring and Assessment Program

acceptance criteria are:

• Hydrogen content – maximum hydrogen content of the cover 

gas over the approved storage period should be extrapolated 

from the gas measurements to be less than the design-bases 

limit for hydrogen content;

• Moisture content – the moisture content in the cask/canister, 
B-22

Element Description

accounting for measurement uncertainty, should be less than 

the expected upper bound moisture content per the designbases drying process2

; and

• Fuel condition/performance3 – nondestructive examination (e.g., 

fission gas analysis) and destructive examination (e.g., to obtain 

data on creep, fission gas release, hydride reorientation, 

cladding oxidation, and cladding mechanical properties) should 

confirm the design-bases fuel condition (i.e., no changes to the 

analyzed fuel configuration considered in the safety analyses of 

the approved design bases).

The applicant should provide information on the design-bases 

characteristics of the dry storage system, with regard to these criteria. 

The applicant should reference the source of specific values, or explain 

any assumptions made, for defining design-bases characteristics of the 

fuel condition/performance. 

7. Corrective 

Actions

The corrective actions are in accordance with the specific- or generallicensee QA Program and consistent with 10 CFR Part 72, Subpart G, 

or 10 CFR Part 50, Appendix B, respectively. 

Corrective actions should be implemented if data from a surrogate 

demonstration program or other sources of information indicate that any 

of the High Burnup Fuel Monitoring and Assessment Program 

acceptance criteria (in Element 6) are not met.

If any of the acceptance criteria are not met, the licensee will: 

(1) assess fuel performance (impacts on fuel and changes to fuel 

configuration); and 

(2) assess the design-bases safety analyses, considering degraded fuel 

performance (and any changes to fuel configuration), to determine the 

ability of the dry storage system to continue to perform its intended 

functions under normal, off-normal, and accident conditions. 

The licensee will determine what corrective actions should be taken to: 

(1) manage fuel performance, if any; or 

(2) manage impacts related to degraded fuel performance to ensure 

that all intended functions for the dry storage system are met. 

 2 The applicant will need to provide the expected upper bound moisture content based on its 

design-bases drying process. If the design-bases drying process involves a vacuum drying method of 

evacuating a cask/canister to less than or equal to 3 torr and maintaining a constant pressure for 30 

minutes after the cask/canister is isolated from the vacuum pump, the expected water content is about 

0.43 gram-mole. (See NUREG-1536, Rev. 1.)

3 While it is not a fuel performance criterion, the spatial distribution and time history of the temperature 

must be known to evaluate the relationship between the performance of the rods in a surrogate 

demonstration program and the high burnup fuel rod behavior expected in the cask.
B-23

Element Description

In addition, the licensee will obtain the necessary NRC approval in the 

appropriate licensing/certification process for modification of the design 

bases to address any conditions outside of the approved design bases.

8. Confirmation 

Process

The confirmation process is commensurate with the specific- or 

general- licensee QA Program and is consistent with 10 CFR Part 72, 

Subpart G, or 10 CFR Part 50, Appendix B, respectively. The QA 

Program ensures that the confirmation process includes provisions to 

ensure corrective actions are adequate and appropriate, have been 

completed, and are effective. The focus of the confirmation process is 

on the follow-up actions that must be taken to verify effective 

implementation of corrective actions. The measure of effectiveness is 

in terms of correcting the adverse condition and precluding repetition of 

significant conditions adverse to quality.

Procedures include provisions for timely evaluation of adverse 

conditions and implementation of any corrective actions required, 

including root cause evaluations and prevention of recurrence where 

appropriate. These procedures provide for tracking, coordinating, 

monitoring, reviewing, verifying, validating, and approving corrective 

actions, to ensure effective corrective actions are taken.

9. Administrative 

Controls

The administrative controls are in accordance with the specific- or 

general-licensee QA Program and consistent with 10 CFR Part 72, 

Subpart G, or 10 CFR Part 50, Appendix B, respectively. The QA 

Program ensures that the administrative controls include provisions that 

define:

• Formal review and approval processes

• Record retention requirements, and

• Document control.

10. Operating 

Experience

The program references and evaluates applicable operating 

experience, including:

• Internal and industry-wide condition reports,

• Internal and industry-wide corrective action reports,

• Vendor-issued safety bulletins,

• NRC Information Notices, 

• Applicable DOE or industry initiatives (e.g., HDRP), and

• Applicable research (e.g., Oak Ridge National Laboratory 

studies on bending responses of the fuel, Argonne National 

Laboratory and Central Research Institute of Electric Power 

Industry studies on hydride reorientation effects).

The review of operating experience clearly identifies any HBU fuel 

degradation as either age-related or event-driven, with proper 

justification for that assessment. Past operating experience supports 

the adequacy of the HBU Fuel Monitoring and Assessment Program.

Surrogate demonstration programs with storage conditions and fuel 
B-24

Element Description

types similar to those in the licensed/certified dry storage system that 

meet the guidance in Appendix D are a viable method to obtain 

operating experience. 

New data/research on fuel performance from both domestic and 

international sources that are relevant to the licensed/certified HBU fuel 

in the dry storage system should be evaluated on a periodic basis.

References Center for Nuclear Waste Regulatory Analyses. 2013. “Extended 

Storage and Transportation: Evaluation of Drying Adequacy,” June 

2013, NRC Contract No. NRC-02-07-006. ADAMS Accession No. 

ML13169A039.

EPRI. 2014. “HBU Dry Storage Cask Research and Development 

Project Final Test Plan,” February 27, 2014, DOE Contract No.: 

DE-NE-0000593.

NRC. 2010. “Standard Review Plan for Spent Fuel Dry Storage 

Systems at a General License Facility,” NUREG-1536, Revision 1, 

Washington, DC. ADAMS Accession No. ML101040620.

NRC. 2003. NRC Interim Staff Guidance 11, “Cladding Considerations 

for the Transportation and Storage of Spent Fuel,” Revision 3, 

November 17, 2003. ADAMS Accession No. ML033230335.

1

2
B-25

1 Table B-4. Formal Evaluations of Aggregate Information on HBU Fuel Performance

2

Year Assessment

1 Date – prior to HBU 

fuel exceeding the 

initial storage term4

Evaluate information obtained from a surrogate demonstration 

program loading and initial period of storage along with other 

available sources of information. If a surrogate demonstration 

program nondestructive examination (NDE) (i.e., cask/canister gas 

sampling, temperature data) has not been obtained at this point, 

then the licensee has to provide evidence that the acceptance 

criteria in Element 6 are met or initiate a corrective action. 

2 Date – 10 years after 

Assessment 1 above

Evaluate, if available, information obtained from the destructive 

examination (DE) and NDE of the fuel placed into storage in a 

surrogate demonstration program along with other available 

sources of information. If the DE data from a surrogate 

demonstration program has not been obtained at this point, then 

the licensee has to provide evidence to the NRC, by opening a 

cask/canister or separate effects surrogate experiments, that the 

acceptance criteria in Element 6 are met or initiate a corrective 

action. 

3 Date – 10 years after 

Assessment 2 above

Evaluate any new information.

3

4

 4 See Appendix F for a discussion of storage terms.

1 APPENDIX C

2 LEAD SYSTEM INSPECTION FOR SPECIFIC LICENSE AND 

3 CERTIFICATE OF COMPLIANCE RENEWALS

C-1

1 Appendix C

2 Lead System Inspection for Specific License and Certificate of 

3 Compliance Renewals

4 C.1 Purpose of the Lead System Inspection

5 Dry storage system (DSS) materials are selected to be resistant to environmentally-induced 

6 degradation during the initial storage period. However, because inspections of the DSSs are 

7 not typically conducted or are limited in scope during the initial storage period, it is important for 

8 an applicant to determine the condition of the system and demonstrate that structures, systems, 

9 and components (SSCs) within the scope of the renewal application have not undergone 

10 unanticipated aging and degradation prior to entering the period of extended operation. If the 

11 system inspection reveals unanticipated aging or degradation, then the applicant would need to 

12 address the condition of the SSCs in the renewal application. A lead system inspection is a 

13 U.S. Nuclear Regulatory Commission (NRC) staff-accepted approach to verify system condition 

14 at an independent spent fuel storage installation (ISFSI).

15 The lead system inspection is an important element in an operations-focused aging 

16 management approach and provides valuable operating experience. This inspection may 

17 provide data to confirm a time-limited aging analysis (TLAA) prediction of the system’s condition 

18 at the end of the initial storage period or to revise TLAAs for the period of extended operation. 

19 The results from the lead system inspection will be used by the applicant to develop detailed 

20 aging management programs (AMPs), including inspection and maintenance frequencies, and 

21 provide a baseline for the monitoring and trending element of AMPs in the period of extended 

22 operation. The staff considers the results of the lead system inspection, in conjunction with 

23 other relevant operating experience (including operating experience that is identified and 

24 evaluated by the applicant) in its review of the renewal application. 

25 C.2 Selecting System(s) for Inspection

26 If multiple storage systems or designs are in use at the ISFSI, then the lead system inspection 

27 should address the different storage systems or designs that are used. The inspection should 

28 include all SSCs within the scope of the renewal application. 

29 The selection of system(s) for inspection should consider the results of the aging management 

30 review and should be based on the degradation mechanism(s) of concern for the SSC. An SSC 

31 for inspection should be selected based on site-specific conditions, system design, material 

32 combinations, and operating parameters that may contribute to aging and degradation. 

33 Consideration should also be given to event-driven (not age-related) fabrication or operational 

34 issues that may contribute to degradation (e.g., welding repairs, occurrence of natural or man35 induced events) when selecting SSCs for inspection.

36 For example, if chloride-induced stress corrosion cracking (CISCC) of a stainless steel canister 

37 is a potential aging mechanism that must be managed in the period of extended operation, then 

38 the inspection should be conducted on the canister that has the greatest susceptibility to 

39 CISCC. The determination of susceptibility may involve the initial heat load of the canister, 

40 expected temperature variations on the canister surface with priority given to the coolest 

41 locations and welds, and the canister location if it is determined that some DSS at a site may be 
C-2

1 located closest to or oriented toward the source of atmospheric chlorides. For concrete aging 

2 due to freeze-thaw cycles of environmental moisture, the inspection may involve the overpack 

3 or horizontal storage module that has been in service for the longest time. Other concrete aging 

4 mechanisms, such as chemical attack or aggregate reactions, are in part dependent on the 

5 specific composition of the concrete placed, including additives, water to cement ratio, and the 

6 aggregate used in the concrete. Therefore, the criteria for lead system selection will not only 

7 depend on length of service. Different lead systems may need to be inspected depending on 

8 the susceptibility to the different aging mechanisms.

9 Therefore, the lead system inspection may involve SSCs in various/multiple DSSs at the ISFSI. 

10 Applicants are encouraged to discuss their considerations for selecting the lead system(s) to 

11 inspect and their plans for the lead system inspection with NRC staff in pre-application meetings 

12 before submitting their renewal application.

13 C.3 Guidelines for the Lead System Inspection

14 The inspections should utilize consensus codes and standards where they exist for the 

15 examination methods, including equipment calibration and personnel qualifications, and 

16 acceptance criteria. Alternatively, applicants may propose the use of an inspection method for 

17 SSCs within the scope of the renewal that has been demonstrated to detect aging effects prior 

18 to a loss of intended function. If a demonstrated surface or volumetric examination method 

19 does not exist yet, visual examination may be used, when appropriate, to determine if aging 

20 effects have occurred on the SSCs within the scope of the review. Visual examination should 

21 also follow consensus codes and standards and be demonstrated on the SSCs subject to 

22 examination. The inspections should consider previous operating experience to determine 

23 areas which may require more thorough examination.

24 The lead system inspection is expected to be performed before submittal of the specific-license 

25 or certificate of compliance (CoC) renewal application. The inspection results become part of 

26 the justification (technical bases) for renewal. The reviewer should evaluate these inspection 

27 results provided with the application.

28 The applicant’s proposed aging management programs should incorporate the results of the 

29 lead system inspection and provide justification for the selection of examination methods, 

30 frequency, and sample size for subsequent inspections in the period of extended operation. 

31 Observations of unexpected conditions or aging effects on an SSC within the scope of the 

32 renewal may require changes to the planned inspection frequency and sample size. In addition, 

33 the applicant should discuss how it handled such lead system inspection findings or 

34 observations, per its quality assurance program.

35 C.4 Use of Surrogate Inspections

36 Because there is not yet a good base of operating experience associated with ISFSI and DSS 

37 inspections, an applicant should not refer to inspections conducted at other sites as a surrogate 

38 for its lead system inspection. Differences in DSS materials, DSS fabrication practices, DSS 

39 design modifications, and environmental conditions at various sites could make comparisons 

40 between different ISFSI sites invalid. 
C-3

1 C.5 Considerations for Lead System Inspections for CoC Renewals 

2 The CoC holder, as the applicant for a CoC renewal, is responsible for demonstrating that the 

3 storage of spent fuel has not, in any significant manner, adversely affected SSCs important to 

4 safety. A lead system inspection is a NRC staff-accepted approach to support this 

5 demonstration and should be performed before submittal of the renewal application, as the 

6 inspection results become part of the justification for renewal. Therefore, the CoC holder should 

7 include the results of lead system inspections in its renewal application. 

8 The CoC holder is, however, in a somewhat unique position regarding lead system inspections. 

9 Unlike specific-license applicants, the CoC holder is responsible for this demonstration for 

10 systems at multiple environments and locations. Moreover, the CoC holder may not own the 

11 deployed DSSs at general-licensed ISFSI sites and may not have the authority to conduct lead 

12 system inspections at general-licensed ISFSI sites. This demonstration, and thus, the lead 

13 system inspection to support it, is nevertheless the responsibility of the CoC holder as applicant. 

14 One acceptable method for making this demonstration is for a lead system inspection to be 

15 conducted for a subset of sites that may be considered bounding for most sites where the 

16 system is used. CoC holders could work within their users groups to identify bounding lead 

17 systems for inspection. General licensees who have systems that may be good candidates for 

18 bounding lead systems could conduct inspections to support the CoC renewal application. If an 

19 approach like this is presented, the reviewer should ensure that the CoC renewal application 

20 provides a clear description of the criteria used to identify these systems as bounding.

21 The preceding discussion (Section C.2 above) on selecting systems for inspection should be 

22 considered in determining the bounding systems, along with the range of environmental 

23 conditions at all existing sites where the DSS is used, variations in designs, materials, and 

24 material combinations in the approved amendments to the CoC, and the potential aging 

25 mechanisms for the SSCs within the scope of renewal.

26 The CoC holder should define an approach for ensuring that all CoC users (general licensees) 

27 are bounded by the lead systems described in the renewal application. An acceptable approach 

is that the CoC users conduct a baseline inspection1 28 at their sites prior to entering their 

respective period of extended operation.2 3 29 The parameters, requirements and timing for this 

30 baseline inspection should be defined in the renewal application (e.g., in each SSC-specific 

31 AMP or in the form of a separate standalone AMP). Each general licensee would conduct a 

32 baseline inspection at its ISFSI site following the criteria in the appropriate AMP. The general 

33 licensee should demonstrate that the results from its baseline inspection did not reveal any 

34 aging effects that were not identified in the bounding lead system inspections of the renewal 

 1 For purposes of this discussion, a baseline inspection is defined as a site-specific inspection conducted 

by a general licensee after the CoC has been renewed, but prior to entering its respective period of 

extended operation. The general licensees would evaluate the results of the baseline inspections against 

those of the bounding lead system inspections described in the renewal application.

2

 The period of extended operation of a general-licensed site is defined by the storage terms of the DSS 

(see Appendix F).

3

 If a CoC is in the period of timely renewal (where the applicant submitted a renewal application within 

the time frames established in the regulations but the NRC has not yet made a final decision concerning 

the renewal application before the CoC expiration date), conducting the baseline inspection before the 

period of extended operation may not be possible. In this case, the applicant should address the timing 

for conducting the baseline inspection, in the renewal application. 
C-4

1 application. The CoC holder should also update the AMPs if these inspection results reveal 

2 inadequacies or need for enhancement.

3 Pursuant to 10 CFR 72.240(e), in approving the renewal, the NRC may revise the CoC to 

4 include terms, conditions, and specifications that will require the implementation of an AMP. 

5 10 CFR 72.212(b)(11) further requires each general licensee to comply with the terms, 

6 conditions, and specifications in the CoC, including the requirements of an AMP. Therefore, the 

7 staff may impose conditions in the renewed CoC to ensure that all general licensees perform a 

8 baseline inspection prior to entering their period of extended operation.
1 APPENDIX D

2 SUPPLEMENTAL GUIDANCE FOR THE USE OF A

3 DEMONSTRATION PROGRAM AS A SURVEILLANCE TOOL FOR 

4 CONFIRMATION OF INTEGRITY OF HIGH BURNUP FUEL DURING

5 THE PERIOD OF EXTENDED OPERATION

D-1

1 Appendix D

2

3 Supplemental Guidance for the Use of a Demonstration Program as a 

4 Surveillance Tool for Confirmation of Integrity of High Burnup Fuel 

5 During the Period of Extended Operation

6 This guidance provides the U.S. Nuclear Regulatory Commission (NRC) staff a basis for reviewing

7 if a demonstration of high burnup (HBU) fuel has the necessary properties to qualify as one

8 method that an applicant might use in license and certificate of compliance applications to 

9 confirm the integrity of HBU fuel during continued storage.

10 D.1 Discussion

11 The experimental confirmatory basis that low burnup fuel (≤45 GWd/MTU) will maintain its 

12 integrity in dry cask storage over extended time periods was provided in a demonstration test 

13 (NRC 2003, Bare et al., 2001, Einziger et al 2003). A similar confirmation test, which includes

14 information over a similar length of the time available for low burnup fuel, does not exist for other 

light water reactor (LWR) fuels, HBU fuel1 15 and mixed oxide fuels. Certification and licensing HBU

16 fuel for storage was permitted for an initial 20-year-term using the guidance contained in Interim 

17 Staff Guidance (ISG) 11 (NRC 2003) which was based on short-term laboratory tests and

18 analysis that may not be applicable to the storage of HBU fuel beyond 20 years, particularly with

19 the current state of knowledge regarding HBU fuel cladding properties.

20 One concern stated in ISG-11 was the potential detrimental effects, such as reduced ductility, of

21 hydride reorientation on cladding behavior (NRC 2003). Research performed in Japan and the 

22 United States indicated that: (1) hydrides could reorient at a significantly lower stress than 

23 previously believed (Billone et al., 2013, Kamimura 2010, Daum et al 2006), and (2) the radial 

24 hydrides could raise the cladding ductile-to-brittle transition temperature enough to compromise 

25 the ability of the cladding to withstand stress without undergoing brittle failure (Billone et al.,

26 2013). This phenomenon could influence the retrievability of HBU fuel assemblies and result in

27 operational safety concerns in the handling of individual assemblies as HBU fuel cooled. 

28 Circumferential zirconium hydrides in the fuel cladding regions would dissolve into the fuel 

29 cladding during drying and reprecipitate (reorient) as radial hydrides as the fuel cladding cooled. 

30 Thus, fuel cladding with radial hydrides that is below a ductile-to-brittle transition temperature

31 could be too brittle to retrieve (remove from the DSS) on an assembly basis. The maximum

32 temperatures and internal rod pressures in ISG-11 were recommended to mitigate hydride

33 reorientation and are applicable to HBU fuel during the initial 20-year storage, as the decay heat

34 of HBU fuel is expected to maintain cladding temperatures above a ductile-to-brittle transition 

35 temperature (~200°C).

36 There is no evidence to suggest that HBU fuel cannot similarly be stored safely and then 

37 retrieved for time periods beyond 20 years, but the supporting experimental data is not 

38 extensive. Therefore, confirmatory data or a commitment to obtain data on HBU fuel and taking

39 appropriate steps in an aging management plan (AMP) will provide further information that will

40 be useful in evaluating the safe handling of individual assemblies of HBU fuel for extended 

41 durations.

 1 High burnup fuel is fuel with burnup ≥ 45 GWd/MTU.
D-2

1 A demonstration program could provide an acceptable method for an applicant to demonstrate 

2 compliance with the cited regulations for storage of light water reactor fuels (LWR) for periods of

3 greater than 20 years by:

4 • Confirming the expected fuel conditions, based on technical arguments made in ISG-11

5 (NRC 2003), after a substantial storage period that is sufficiently long (~ 10 years) to 

6 extrapolate the findings to the storage duration of interest. The behavior of the cladding

7 for the period of extended operation will depend on its physical condition at the end of the

8 initial 20-year storage period.

9 • Providing data for benchmarking, confirming predictive models, and updating aging 

10 management plans.

11 • Confirming the time-limited aging analysis (TLAA) cladding creep predictions that are the 

12 basis for the guidance recommendation for the maximum temperature in ISG-11 (NRC 

13 2003) are not exceeded and that sufficient creep margin exists for the extended storage 

14 period.

15 • Determining the system is sufficiently dry to eliminate moisture-driven degradation from 

16 consideration.

17 • Providing operational experience on the fuel behavior and drying procedure as input to 

18 an AMP on the behavior of the fuel.

19 • Identifying any aging effects that may be missed through short-term accelerated studies 

20 and analyses.

21 Monitoring of the fuel temperatures, gas composition, and other conditions in the canister or cask

22 combined with physical examination of the fuel at periodic intervals should be able to provide

23 confirmation if:

24 • The models of the phenomena used for the first 20-year predictions can be used for the 

25 TLAA beyond 20 years.

26 • The condition of the fuel, after an appropriately long period of storage, does not degrade.

27 • New degradation mechanisms are not being exhibited.

28 Extrapolation outside the recorded data carries risk, but that risk can be minimized if the length of

29 the extrapolation is reduced and those extrapolations are updated as the demonstration 

30 continues to monitor and measure fuel properties.

31 D.2 Technical Review Guidance:

32 The applicant may use the results of a completed demonstration or an on-going demonstration if 

33 the conditions of the demonstration meet the requirements stated below for the fuels and 

34 conditions of storage for which the term is to be renewed. The approach in this guidance can be 

35 applied to a generic demonstration program or a site/system-specific program as long as the 

36 demonstration’s parameters are reasonably applicable to the applicant’s fuel type and characteristics.

37 The technical reviewers should establish that the following conditions are met if the 

38 demonstration is to be used by the applicant to support fuel assembly conditions for storage of

39 LWR fuel beyond 20 years and to be applicable to support a license or certificate application:

40 1. That the maximum burnup of the fuel in the application is less than the burnup of the fuel 
D-3

1 in the demonstration. If the burnup is higher than that in the demonstration, the 

2 applicant should provide evidence, based on characteristics of the fuel, derived either 

3 from reactor rod qualification testing or other separate effects tests, that the 

4 demonstration fuel is reasonably characteristic of the stored fuel and the added burnup 

5 will not change the results determined by the demonstration. Similarly, if there is a 

6 different cladding type used, arguments based on comparison of composition and 

7 fabrication technique (e.g., stress-relieved and annealed, recrystallized) should justify 

8 the use of the demonstration results.

9 2. If the applicant uses direct observations of the rod behavior to imply the condition of the 

10 rods in its system, either (a) the temperatures in the demonstration must bound the 

11 temperatures in the application, or (b) if the applicant uses predictive tools that have 

12 been confirmed by the demonstration, then the temperatures of the rods in the 

13 application do not have to be bounded by the temperature of the rods in the 

14 demonstration. The temperature models used in the application should either be 

15 benchmarked (a) against the demonstration temperature data, or (b) against actual 

16 measured rod temperature data in the same temperature range.

17 3. If the applicant is using gas analysis or another gas detection method to establish the 

18 condition of the fuel, then the interior of a demonstration canister or cask should be 

19 quantitatively monitored for, at a minimum, moisture, oxygen, and fission gas. The 

20 duration and frequency of the gas monitoring should be determined by analysis of the 

21 potential degradation. Gases should always be quantitatively monitored prior to opening 

22 of the canister. If the applicant claims that no galvanic degradation is feasible, then, if 

23 after drying, moisture is detected in the canister, moisture and H2 should be monitored at 

24 a reasonable frequency to be determined by the applicant until the moisture disappears. 

25 Gas monitoring is not expected during movement of the canister. If the applicant is 

26 using the gas analysis to show no breaches would occur during transport, gas 

27 quantitative monitoring must be conducted before and after transport.

28 4. Temperature monitoring should be conducted at a frequency that is suitable for 

29 determining the profile over the duration of the demonstration.

30 5. If possible, some population of stored rods should be examined whenever the system is 

31 opened. These rods should be extracted from the fuel assembly to determine properties of 

32 the rods that affect degradation such as cladding creep, fission gas release, hydride

33 reorientation, cladding oxidation, and mechanical properties.

34 6. The demonstration program fuel shall include at least two full fuel assemblies. The 

35 assemblies may be reconstituted.

36 7 . Data from the demonstration program must be indicative of a storage duration long 

37 enough to justify extrapolation to the total storage time requested but no less than

38 10 years if the data is to be used to support license extension from the initial 20 years to

an additional 40 years2 39 .

 2 A demonstration is to provide that there was satisfactory performance during the first 20 years and that 

the results could be extrapolated to support an additional 40 years. The NRC staff agreed that a 

demonstration of ≤ 10 years storage duration is insufficient to support these goals.
D-4

1 D.3 References

2 Bare, W.C, L.D. Torgerson. 2001. “Dry Cask Storage Characterization Project-Phase 1: 

3 CASTOR V/21 Cask Opening and Examination,” NUREG/CR-6745, Idaho National Engineering

4 and Environmental Lab, Idaho Falls, ID. Agencywide Documents Access and Management 

5 System (ADAMS) Accession No. ML013020363. 

6 M.C. Billone, T.A. Burtseva, and R.E. Einziger. 2013. “Ductile-to-Brittle Transition Temperature 

7 for High-Burnup Cladding Alloys Exposed to Simulated Drying-Storage Conditions,” Journal of 

8 Nuclear Materials, Volume 433, Issues 1–3, pages 431–448, February 2013.

9 R.S. Daum, S. Majumbdar, Y. Liu, and M.C. Billone. 2006. “Radial-hydride Embrittlement of 

10 High-burnup Zircaloy-4 Cladding”, Journal of Nuclear Science and Technology, Vol. 43, No. 9, 

11 p.1054, 2006.

12 Einziger, R.E., H. Tsai, M.C. Billone, B.A. Hilton. 2003. “Examination of Spent PWR Fuel Rods

13 after 15 Years in Dry Storage,” NUREG/CR-6831, Argonne National Laboratory, Argonne, IL. 

14 ADAMS Accession No. ML032731021.

15 K. Kamimura. 2010. “Integrity Criteria of Spent Fuel for Dry Storage in Japan” Proc. 

16 International Seminar on Interim Storage of Spent Fuel, ISSF 2010, Tokyo Nov 2010, page 

17 VI3-1.

18 NRC. 2003. NRC Interim Staff Guidance 11, “Cladding Considerations for the Transportation 

19 and Storage of Spent Fuel,” Revision 3, November 17, 2003.
1 APPENDIX E

2 CONSIDERATIONS FOR RENEWALS

3 OF CERTIFICATES OF COMPLIANCE

E-1

1 Appendix E

2 Considerations for Renewals of Certificates of Compliance

3 E.1 Development of Time-Limited Aging Analyses and Aging Management Programs

4 Per Title 10 of the Code of Federal Regulations (10 CFR) 72.240, “Conditions for Spent Fuel 

5 Storage Cask Renewal,” the certificate of compliance (CoC) renewal application must include 

6 time-limited aging analyses (TLAAs), if applicable, and aging management programs (AMPs). 

7 The CoC holder, as the applicant for the CoC renewal and the owner of the storage cask 

8 design, will develop the TLAAs and AMPs. The renewal application should address age-related 

9 degradation of the dry storage system (DSS) design in a bounding manner (i.e., fully address 

10 pertinent aging mechanisms and effects in all possible service environments where the DSS is 

11 being used and can be used). If there is an AMP that may not be applicable to certain CoC 

12 users, because of the service environment in which the DSS is located, the AMP should specify 

13 this. In addition, the CoC holder and the staff should consider the need for a CoC condition to 

14 specify this potential limited use of the AMP, so it is clear for general licensee implementation.

15 For a CoC renewal that encompasses CoC amendments with different design bases, the CoC 

16 holder will need to address in the renewal application how the TLAAs or AMPs apply to each 

17 amendment covered by the CoC. For example, if different materials are used in different CoC

18 amendments, or if different environments (e.g., underground vs. aboveground system) are 

19 reflected in different CoC amendments, then there may be different TLAAs or AMPs specified 

20 for the individual amendments. 

21 E.2 Implementation of AMPs

22 In approving the renewal of the DSS design, the U.S. Nuclear Regulatory Commission (NRC)

23 may revise the CoC to include terms, conditions, and specifications that will ensure the safe 

24 operation of the DSS during the period of extended operation, including but not limited to, terms, 

25 conditions, and specifications that will require the implementation of an AMP by a general 

26 licensee, in accordance with 10 CFR 72.240(e).

27 Regulations in 10 CFR 72.212, “Conditions of General License Issued under § 72.210,” provide

28 requirements for general licensees using approved CoCs. Regulations in 10 CFR 72.212(b)(11) 

29 require general licensees to comply with the terms, conditions, and specifications of the CoC, 

30 including but not limited to, the requirements of any AMP put into effect as a condition of the 

31 NRC approval of a CoC renewal application in accordance with 10 CFR 72.240.

32 General licensees (CoC users) are responsible for implementing the AMPs. To document the 

33 licensee’s compliance with the renewed CoC, the general licensee should update the evaluation 

34 required under 10 CFR 72.212(b)(5) to show how it will meet the new CoC terms, conditions, or 

35 specifications for aging management. The licensee should update the 10 CFR 72.212(b)(5) 

36 evaluation before entering the period of extended operation. If AMP details in the FSAR specify

37 that the AMP is not applicable for certain users (e.g., if it is not applicable in certain climates or 

38 environments), the general licensee can include the technical justification in its 

39 10 CFR 72.212(b)(5) report for not implementing such an AMP. The general licensee would 

40 need to evaluate any changes to the 10 CFR 72.212(b)(5) report, using the requirements of 

41 10 CFR 72.48 (See NRC Regulatory Issue Summary 2012-05, “Clarifying the Relationship 

42 Between 10 CFR 72.212 and 10 CFR 72.48 Evaluations”). 
E-2

1

2 E.3 Corrective Actions

3 As discussed in Section 3.6, corrective actions are measures to be taken when the AMP 

4 acceptance criteria are not met. Corrective actions are critical for maintaining the intended 

5 functions of the structures, systems, and components during the initial storage term as well as 

6 the period of extended operation. The CoC holder should discuss in its renewal application the 

7 applicable and appropriate corrective actions that may be taken if the AMP acceptance criteria 

8 are not met. 

9 A general licensee will use its Corrective Action Program (CAP) (that is consistent with the 

10 criteria in 10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants 

11 and Fuel Reprocessing Plants”) to capture and address aging effects identified in the period of 

12 extended operation. In this case, all conditions that do not meet the AMP acceptance criteria 

13 should be entered into the CAP. The general licensee’s CAP should be able to respond to and 

14 adequately address and rectify any ISFSI or DSS aging issues. Also, the CAP’s response to 

15 address any DSS aging issues should include any specific corrective actions specified in the 

16 CoC renewal application.
1 APPENDIX

F

2 STORAGE TERMS

F-1

1 Appendix F

2 Storage Terms

3 F.1 Introduction

4 This appendix provides a flow chart for calculating storage terms of a dry storage system (DSS)

5 loaded during either the initial storage period or renewal period(s) of a certificate of compliance 

6 (CoC).

7 F.2 Storage Term Defined

8 The storage term (length of time a DSS can remain loaded) is determined by the period 

9 specified in the applicable certificate of compliance (CoC) in effect at the time the DSS is placed 

10 into service (from Title 10 of the Code of Federal Regulations (10 CFR) 72.212(a)(3) and 

11 Ref. 1). The initial storage period begins when the DSS is first used by the general licensee to 

12 store spent fuel (10 CFR 72.212(a)(3)). The clock starts when the loaded cask has been 

13 deployed in the ISFSI (76 FR 8872). Pursuant to 10 CFR 72.212(a)(3), the general license for 

14 storage of spent fuel in each cask terminates when the CoC expires. If a CoC is not renewed, 

15 upon expiration, casks loaded under that CoC would need to be removed from service. 

16 • If the DSS is loaded during the initial CoC term (e.g., 20 years) and the CoC is not 

17 renewed, the storage term is the entirety of the initial CoC term (e.g., 20 years).

18

19 • If the DSS is loaded during the initial CoC term and the CoC is renewed once, the 

20 storage term is the remaining time in the initial CoC term added to the entirety of the first 

21 renewal period.

22

23 • If the DSS is loaded during the first renewal period (e.g., 40 years), and the CoC is not 

24 subsequently renewed, the storage term is the entirety of the first renewal period (e.g.,

25 40 years).

26

27 • If the DSS is loaded during the first renewal period, and the CoC is subsequently 

28 renewed, the storage term is the remaining time in the first renewal period added to the 

29 entirety of the subsequent renewal period (cumulative).

30 F.3 Flowchart for Calculating Storage Terms

31 A flowchart is provided below to assist the user in calculating the storage term for a DSS loaded 

32 under a CoC.
F-2

Loaded 

during initial 

CoC term?

Subsequently 

renewed?

Start

Renewed?

A = 0

B= full length of first 

renewal period 

(years)

C = 0

A = 0

B = remaining time in first 

renewal period (years)

C = any subsequent 

renewal period(s) 

[cumulative, in years]

A = remaining time in the 

initial license period (years)

B = full length of first 

renewal period (years)

C = any subsequent 

renewal period(s) 

[cumulative, in years]

A = full length of initial 

license period (years)

B = 0

C = 0

Yes

No

Yes

No

No

Yes

Yes

Loaded during 

first renewal 

period?

Length of storage term = A + B + C

1

2 Figure F-1. Flowchart for Calculating Storage Terms

3

4 F.4 References

5 76 FR 8872. February 16, 2011. “10 CFR Part 72, License and Certificate of Compliance 

6 Terms, Final Rule.” Federal Register, U.S. Nuclear Regulatory Commission, Washington, DC.

7


NUREG-1927, Rev. 1

Draft

Standard Review Plan for Renewal of Specific Licenses and Certificates of 

Compliance for Dry Storage of Spent Nuclear Fuel