Standard Review Plan for 

Review of Subsequent 

License Renewal 

Applications for Nuclear 

Power Plants

 

Draft Report for Comment

Office of Nuclear Reactor Regulation

NUREG-2192
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Standard Review Plan for 

Review of Subsequent 

License Renewal 

Applications for Nuclear 

Power Plants

Draft Report for Comment

Manuscript Completed: October 2015 

Date Published: December 2015

Office of Nuclear Reactor Regulation

NUREG-2192

 

1 COMMENTS ON DRAFT REPORT

2 Any interested party may submit comments on this report for consideration by the U.S. Nuclear 

3 Regulatory Commission (NRC) staff. Comments may be accompanied by additional relevant 

4 information or supporting data. Please specify the report number NUREG–2191, Volume 2, in 

5 your comments, and send them by the end of the comment period specified in the 

6 Federal Register notice announcing the availability of this report. 

7 Addresses: You may submit comments by any one of the following methods. Please include 

8 Docket ID NRC–2015–0251 in the subject line of your comments. Comments submitted in 

9 writing or in electronic form will be posted on the NRC website and on the Federal rulemaking 

10 website http://www.regulations.gov. 

11 Federal Rulemaking Website: Go to http://www.regulations.gov and search for documents 

12 filed under Docket ID NRC–2015–0251. Address questions about NRC dockets to 

13 Carol Gallagher at 301-415-3463 or by e-mail at Carol.Gallagher@nrc.gov. 

14 Mail comments to: Cindy Bladey, Chief, Rules, Announcements, and Directives Branch 

15 (RADB), Division of Administrative Services, Office of Administration, Mail Stop: 

16 OWFN-12-H08, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. 

17 For any questions about the material in this report, please contact: Bennett Brady, 

18 Senior Project Manager, 301-415-2981 or by e-mail at Bennett.Brady@nrc.gov. 

19 Please be aware that any comments that you submit to the NRC will be considered a public 

20 record and entered into the Agencywide Documents Access and Management System 

21 (ADAMS). Do not provide information you would not want to be publicly available. 

iii 

1 ABSTRACT 

2 The U.S. Nuclear Regulatory Commission (NRC) staff has defined subsequent license renewal 

3 to be the period of extended operation from 60 years to 80 years following initial licensing. The 

4 Standard Review Plan for Review of Subsequent License Renewal Applications (SRP-SLR) for 

5 Nuclear Power Plants provides guidance to NRC staff reviewers in the Office of Nuclear Reactor 

6 Regulation. These reviewers perform safety reviews of applications to renew nuclear power 

7 plant licenses in accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 54 

8 “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.” The NRC 

9 regulations in 10 CFR 54.29 establish the standards for issuance of a renewed license. For 

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

11 state that “a renewed license may be subsequently renewed in accordance with all applicable 

12 requirements.” The NRC has stated that the requirements for subsequent renewal “include the 

13 provisions of part 54 (unless the Commission subsequently adopts special provisions applicable 

14 only to subsequent renewals).” Statement of Consideration, “Nuclear Power Plant License 

15 Renewal,” 56 FR 64,943, 64,964-65 (Dec. 13, 1991). To date, the NRC has not adopted special 

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

17 continues to govern subsequent license renewal. 

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

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

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

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

22 make regulatory information widely available to enhance communication with interested 

23 members of the public and the nuclear power industry and to improve public and industry 

24 understanding of the NRC staff’s review process. The safety review is based primarily on the 

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

26 individual SRP-SLR sections addresses (i) who performs the review, (ii) the areas of review, 

27 (iii) the basis for review, (iv) the method of review, and (v) the conclusions from the review. 

v 

1 TABLE OF CONTENTS 

2 Section Page 

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

4 LIST OF TABLES ....................................................................................................................... xxi 

5 LIST OF CONTRIBUTORS ...................................................................................................... xxiii 

6 ABBREVIATIONS ................................................................................................................... xxvii 

7 INTRODUCTION ...................................................................................................................... xxxi 

8 1 ADMINISTRATIVE INFORMATION ........................................................................... 1.1-1

9 1.1 Docketing of Timely and Sufficient Renewal Application ......................... 1.1-1 

10 1.1.1 Areas of Review ................................................................................. 1.1-1 

11 1.1.1.1 Docketing and Sufficiency of Application ........................... 1.1-1 

12 1.1.1.2 Timeliness of Application ................................................... 1.1-1 

13 1.1.2 Acceptance Criteria ........................................................................... 1.1-2 

14 1.1.2.1 Docketing and Sufficiency of Application ........................... 1.1-2 

15 1.1.2.2 Timeliness of Application ................................................... 1.1-2 

16 1.1.3 Review Procedures............................................................................ 1.1-2 

17 1.1.3.1 Docketing and Sufficiency of Application ........................... 1.1-2 

18 1.1.3.2 Timeliness of Application ................................................... 1.1-3 

19 1.1.4 Evaluation Findings........................................................................... 1.1-4 

20 1.1.5 Implementation .................................................................................. 1.1-4 

21 1.1.6 References ......................................................................................... 1.1-4 

22 2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING 

23 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT 

24 REVIEW AND IMPLEMENTATION RESULTS .......................................................... 2.1-1

25 2.1 Scoping and Screening Methodology ......................................................... 2.1-1 

26 2.1.1 Areas of Review ................................................................................. 2.1-1 

27 2.1.1.1 Scoping .............................................................................. 2.1-1 

28 2.1.1.2 Screening ........................................................................... 2.1-1 

29 2.1.2 Acceptance Criteria ........................................................................... 2.1-2 

30 2.1.2.1 Scoping .............................................................................. 2.1-2 

31 2.1.2.2 Screening ........................................................................... 2.1-2 

32 2.1.3 Review Procedures............................................................................ 2.1-2 

33 2.1.3.1 Scoping .............................................................................. 2.1-4 

34 2.1.3.1.1 Safety-Related .................................................. 2.1-5 

35 2.1.3.1.2 Nonsafety-Related ............................................ 2.1-6 

36 2.1.3.1.3 “Regulated Events” ........................................... 2.1-8 

37 2.1.3.2 Screening ........................................................................... 2.1-9 

38 2.1.3.2.1 “Passive” .......................................................... 2.1-9 

39 2.1.3.2.2 “Long-Lived” ................................................... 2.1-10 

40 2.1.4 Evaluation Findings ......................................................................... 2.1-11 

41 2.1.5 Implementation ................................................................................ 2.1-11 

42 2.1.6 References ....................................................................................... 2.1-11 

43 2.2 Plant-Level Scoping Results ........................................................................ 2.2-1 

44 2.2.1 Areas of Review ................................................................................. 2.2-1 

45 2.2.1.1 Systems and Structures Within the Scope of 

46 Subsequent License Renewal ........................................... 2.2-2
vi 

1 2.2.2 Acceptance Criteria ........................................................................... 2.2-2 

2 2.2.2.1 Systems and Structures Within the Scope of 

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

4 2.2.3 Review Procedures............................................................................ 2.2-2 

5 2.2.3.1 Systems and Structures Within the Scope of 

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

7 2.2.4 Evaluation Findings........................................................................... 2.2-4 

8 2.2.5 Implementation .................................................................................. 2.2-4 

9 2.2.6 References ......................................................................................... 2.2-4 

10 2.3 Scoping And Screening Results: Mechanical Systems............................ 2.3-1 

11 2.3.1 Areas of Review ................................................................................. 2.3-1 

12 2.3.2 Acceptance Criteria ........................................................................... 2.3-2 

13 2.3.2.1 Components Within the Scope of Subsequent 

14 License Renewal ................................................................ 2.3-2 

15 2.3.2.2 Components Subject to an Aging 

16 Management Review ......................................................... 2.3-3 

17 2.3.3 Review Procedures............................................................................ 2.3-3 

18 2.3.3.1 Components Within the Scope of Subsequent 

19 License Renewal ................................................................ 2.3-3 

20 2.3.3.2 Components Subject to an Aging 

21 Management Review ......................................................... 2.3-4 

22 2.3.4 Evaluation Findings........................................................................... 2.3-5 

23 2.3.5 Implementation .................................................................................. 2.3-5 

24 2.3.6 References ......................................................................................... 2.3-5 

25 2.4 Scoping and Screening Results: Structures ............................................. 2.4-1 

26 2.4.1 Areas of Review ................................................................................. 2.4-1 

27 2.4.2 Acceptance Criteria ........................................................................... 2.4-2 

28 2.4.2.1 Structural Components Subject to an Aging 

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

30 2.4.3 Review Procedures............................................................................ 2.4-3 

31 2.4.3.1 Structural Components Within the Scope of 

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

33 2.4.3.2 Structural Components Subject to an Aging 

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

35 2.4.4 Evaluation Findings........................................................................... 2.4-5 

36 2.4.5 Implementation .................................................................................. 2.4-5 

37 2.4.6 References ......................................................................................... 2.4-5 

38 2.5 Scoping and Screening Results: Electrical And Instrumentation 

39 and Controls Systems .................................................................................. 2.5-1 

40 2.5.1 Areas of Review ................................................................................. 2.5-1 

41 2.5.2. Acceptance Criteria ........................................................................... 2.5-2 

42 2.5.2.1 Components Within the Scope of Subsequent 

43 License Renewal ................................................................ 2.5-2 

44 2.5.2.1.1 Components Within the Scope of SBO 

45 (10 CFR 50.63) ................................................. 2.5-3 

46 2.5.2.2 Components Subject to an Aging 

47 Management Review ......................................................... 2.5-3 

48 2.5.3 Review Procedures............................................................................ 2.5-3 

49 2.5.3.1 Components Within the Scope of Subsequent 

50 License Renewal ................................................................ 2.5-4
vii 

1 2.5.3.2 Components Subject to an Aging 

2 Management Review ......................................................... 2.5-5 

3 2.5.4 Evaluation Findings........................................................................... 2.5-6 

4 2.5.5 Implementation .................................................................................. 2.5-6 

5 2.5.6 References ......................................................................................... 2.5-6 

6 3 AGING MANAGEMENT REVIEW .............................................................................. 3.0-1 

7 3.0 Integrated Plant Assessments and Aging Management Reviews ............ 3.0-1 

8 3.0.1 Background on the Types of Reviews ............................................. 3.0-1 

9 3.0.2 Applications With Approved Extended Power Uprates ................. 3.0-5 

10 3.0.3 Aging Management Programs that Rely on Implementation 

11 of Nuclear Regulatory Commission-Approved Technical or 

12 Topical Reports.................................................................................. 3.0-6 

13 3.1 Aging Management Of Reactor Vessel, Internals, And Reactor 

14 Coolant System ............................................................................................. 3.1-1 

15 3.1.1 Areas of Review ................................................................................. 3.1-1 

16 3.1.2 Acceptance Criteria ........................................................................... 3.1-2 

17 3.1.2.1 Aging Management Review Results Consistent With 

18 the Generic Aging Lessons Learned for Subsequent 

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

20 3.1.2.2 Aging Management Review Results for Which Further 

21 Evaluation Is Recommended by the Generic Aging 

22 Lessons Learned for Subsequent License 

23 Renewal Report ................................................................. 3.1-2 

24 3.1.2.2.1 Cumulative Fatigue Damage ............................ 3.1-2 

25 3.1.2.2.2 Loss of Material Due to General, Pitting, 

26 and Crevice Corrosion ...................................... 3.1-2 

27 3.1.2.2.3 Loss of Fracture Toughness Due to 

28 Neutron Irradiation Embrittlement .................... 3.1-3 

29 3.1.2.2.4 Cracking Due to Stress Corrosion 

30 Cracking and Intergranular Stress 

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

32 3.1.2.2.5 Crack Growth Due to Cyclic Loading ............... 3.1-5 

33 3.1.2.2.6 Cracking Due to Stress Corrosion Cracking ..... 3.1-5 

34 3.1.2.2.7 Cracking Due to Cyclic Loading ....................... 3.1-5 

35 3.1.2.2.8 Loss of Material Due to Erosion ....................... 3.1-6 

36 3.1.2.2.9 Aging Management of Pressurized Water 

37 Reactor Vessel Internals (Applicable to 

38 Subsequent License Renewal 

39 Periods Only) .................................................... 3.1-6 

40 3.1.2.2.10 Loss of Material Due to Wear ........................... 3.1-7 

41 3.1.2.2.11 Cracking Due to Primary Water Stress 

42 Corrosion Cracking ........................................... 3.1-7 

43 3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress 

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

45 3.1.2.2.13 Loss of Fracture Toughness Due to Neutron 

46 Irradiation or Thermal Aging Embrittlement ...... 3.1-9 

47 3.1.2.2.14 Loss of Preload Due to Thermal or 

48 Irradiation Enhanced Stress Relaxation ........... 3.1-9 

49 3.1.2.2.15 Loss of Material Due to Boric 

50 Acid Corrosion ................................................ 3.1-10 
viii 

1 3.1.2.2.16 Cracking Due to Cyclic Loading ..................... 3.1-11 

2 3.1.2.2.17 Cracking Due to Stress Corrosion 

3 Cracking or Intergranular Stress 

4 Corrosion Cracking ......................................... 3.1-11 

5 3.1.2.2.18 Loss of Material Due to General, Crevice 

6 Pitting Corrosion and Microbiologically7 Induced Corrosion and Cracking Due to 

8 Stress Corrosion Cracking ............................. 3.1-12 

9 3.1.2.2.19 Loss of Material Due to Pitting and Crevice 

10 Corrosion and Microbiologically-Induced 

11 Corrosion in Components Exposed to Treated 

12 Water, Treated Borated Water, or Sodium 

13 Pentaborate Solution ...................................... 3.1-12 

14 3.1.2.2.20 Quality Assurance for Aging Management 

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

16 3.1.2.2.21 Ongoing Review of Operating Experience ..... 3.1-13 

17 3.1.2.3 Aging Management Review Results Not Consistent 

18 With or Not Addressed in the Generic Aging Lessons 

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

20 3.1.2.4 Aging Management Programs ......................................... 3.1-13 

21 3.1.2.5 Final Safety Analysis Report Supplement ........................ 3.1-14 

22 3.1.3 Review Procedures.......................................................................... 3.1-14 

23 3.1.3.1 Aging Management Review Results Consistent With 

24 the Generic Aging Lessons Learned for Subsequent 

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

26 3.1.3.2 Aging Management Review Results for Which 

27 Further Evaluation Is Recommended by the Generic 

28 Aging Lessons Learned for Subsequent License 

29 Renewal Report ............................................................... 3.1-15 

30 3.1.3.2.1 Cumulative Fatigue Damage .......................... 3.1-15 

31 3.1.3.2.2 Loss of Material Due to General, Pitting, 

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

33 3.1.3.2.3 Loss of Fracture Toughness Due to 

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

35 3.1.3.2.4 Cracking Due to Stress Corrosion 

36 Cracking and Intergranular Stress 

37 Corrosion Cracking ......................................... 3.1-17 

38 3.1.3.2.5 Crack Growth Due to Cyclic Loading ............. 3.1-17 

39 3.1.3.2.6 Cracking Due to Stress Corrosion Cracking ... 3.1-17 

40 3.1.3.2.7 Cracking Due to Cyclic Loading ..................... 3.1-17 

41 3.1.3.2.8 Loss of Material Due to Erosion ..................... 3.1-18 

42 3.1.3.2.9 Aging Management of PWR Reactor 

43 Vessel Internals (Applicable to Subsequent 

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

45 3.1.3.2.10 Loss of Material Due to Wear ......................... 3.1-19 

46 3.1.3.2.11 Cracking Due to Primary Water Stress 

47 Corrosion Cracking ......................................... 3.1-19 

48 3.1.3.2.12 Cracking Due to Irradiation-Assisted 

49 Stress Corrosion Cracking ............................. 3.1-20
ix 

1 3.1.3.2.13 Loss of Fracture Toughness Due to 

2 Neutron Irradiation or Thermal 

3 Aging Embrittlement ....................................... 3.1-20 

4 3.1.3.2.14 Loss of Preload Due to Thermal or 

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

6 3.1.3.2.15 Loss of Material Due to Boric 

7 Acid Corrosion ................................................ 3.1-22 

8 3.1.3.2.16 Cracking Due to Cyclic Loading ..................... 3.1-22 

9 3.1.3.2.17 Cracking Due to Stress Corrosion Cracking 

10 or Intergranular Stress Corrosion Cracking .... 3.1-22 

11 3.1.3.2.18 Loss of Material Due to General, Crevice 

12 or Pitting Corrosion and Microbiologically 

13 -Induced Corrosion and Cracking Due to 

14 Stress Corrosion Cracking ............................. 3.1-23 

15 3.1.3.2.19 Loss of Material Due to Pitting and Crevice 

16 Corrosion and Microbiologically-Induced 

17 Corrosion in Components Exposed to 

18 Treated Water, Treated Borated Water, 

19 or Sodium Pentaborate Solution .................... 3.1-23 

20 3.1.3.2.20 Quality Assurance for Aging Management 

21 of Nonsafety-Related Components ................ 3.1-24 

22 3.1.3.2.21 Ongoing Review of Operating Experience ..... 3.1-24 

23 3.1.3.3 Aging Managing Review Results Not Consistent With 

24 or Not Addressed in the Generic Aging Lessons 

25 Learned for Subsequent License Renewal Report .......... 3.1-24 

26 3.1.3.4 Aging Management Programs ......................................... 3.1-24 

27 3.1.3.5 Final Safety Analysis Report Supplement ........................ 3.1-25 

28 3.1.4 Evaluation Findings......................................................................... 3.1-25 

29 3.1.5 Implementation ................................................................................ 3.1-25 

30 3.1.6 References ....................................................................................... 3.1-26 

31 3.2 Aging Management of Engineered Safety Features................................... 3.2-1 

32 3.2.1 Areas of Review ................................................................................. 3.2-1 

33 3.2.2 Acceptance Criteria ........................................................................... 3.2-2 

34 3.2.2.1 AMR Results Consistent With the Generic Aging 

35 Lessons Learned for Subsequent License 

36 Renewal Report ................................................................. 3.2-2 

37 3.2.2.2 Aging Management Review Results for Which Further 

38 Evaluation Is Recommended by the Generic Aging 

39 Lessons Learned for Subsequent License 

40 Renewal Report ................................................................. 3.2-2 

41 3.2.2.2.1 Cumulative Fatigue Damage ............................ 3.2-2 

42 3.2.2.2.2 Loss of Material Due to Pitting and 

43 Crevice Corrosion ............................................. 3.2-2 

44 3.2.2.2.3 Loss of Material Due to Erosion ....................... 3.2-4 

45 3.2.2.2.4 Loss of Material Due to General Corrosion 

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

47 3.2.2.2.5 Cracking Due to Stress Corrosion Cracking ..... 3.2-4 

48 3.2.2.2.6 Quality Assurance for Aging Management of 

49 Nonsafety-Related Components ...................... 3.2-5 

50 3.2.2.2.7 Ongoing Review of Operating Experience ....... 3.2-5 
x 

1 3.2.2.2.8 Loss of Material Due to Recurring 

2 Internal Corrosion ............................................. 3.2-5 

3 3.2.2.2.9 Cracking Due to Stress Corrosion Cracking 

4 and Intergranular Stress Corrosion Cracking ... 3.2-6 

5 3.2.2.2.10 Cracking Due to Stress Corrosion Cracking 

6 in Aluminum Alloys ........................................... 3.2-7 

7 3.2.2.2.11 Loss of Material Due to General, Crevice 

8 or Pitting Corrosion and Microbiologically9 Induced Corrosion and Cracking Due to Stress 

10 Corrosion Cracking ........................................... 3.2-8 

11 3.2.2.2.12 Loss of Material Due to Pitting and Crevice 

12 Corrosion and Microbiologically-Induced 

13 Corrosion in Components Exposed to 

14 Treated Water, Treated Borated Water, or 

15 Sodium Pentaborate Solution ........................... 3.2-9 

16 3.2.2.2.13 Loss of Material Due to Pitting and Crevice 

17 Corrosion in Aluminum Alloys .......................... 3.2-9 

18 3.2.2.3 Aging Management Review Results Not Consistent 

19 With or Not Addressed in the Generic Aging Lessons 

20 Learned for Subsequent License Renewal Report .......... 3.2-10 

21 3.2.2.4 Aging Management Programs ......................................... 3.2-10 

22 3.2.2.5 Final Safety Analysis Report Supplement ........................ 3.2-11 

23 3.2.3 Review Procedures.......................................................................... 3.2-11 

24 3.2.3.1 Aging Management Review Results Consistent With 

25 the Generic Aging Lessons Learned for Subsequent 

26 License Renewal Report .................................................. 3.2-11 

27 3.2.3.2 Aging Management Review Results for Which Further 

28 Evaluation Is Recommended by the Generic Aging 

29 Lessons Learned for Subsequent License 

30 Renewal Report ............................................................... 3.2-12 

31 3.2.3.2.1 Cumulative Fatigue Damage .......................... 3.2-12 

32 3.2.3.2.2 Loss of Material Due to Pitting and 

33 Crevice Corrosion ........................................... 3.2-12 

34 3.2.3.2.3 Loss of Material Due to Erosion ..................... 3.2-12 

35 3.2.3.2.4 Loss of Material Due to General Corrosion 

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

37 3.2.3.2.5 Cracking Due to Stress Corrosion Cracking ... 3.2-13 

38 3.2.3.2.6 Quality Assurance for Aging Management 

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

40 3.2.3.2.7 Ongoing Review of Operating Experience ..... 3.2-13 

41 3.2.3.2.8 Loss of Material Due to Recurring 

42 Internal Corrosion ........................................... 3.2-13 

43 3.2.3.2.9 Cracking Due to Stress Corrosion Cracking 

44 and Intergranular Stress Corrosion Cracking . 3.2-14 

45 3.2.3.2.10 Cracking Due to Stress Corrosion Cracking 

46 In Aluminum Alloys ......................................... 3.2-14 

47 3.2.3.2.11 Loss of Material Due to General, Crevice 

48 or Pitting Corrosion and Microbiologically49 Induced Corrosion and Cracking Due to Stress 

50 Corrosion Cracking ......................................... 3.2-16 
xi 

1 3.2.3.2.12 Loss of Material Due to Pitting and 

2 Crevice Corrosion and Microbiologically3 Induced Corrosion in Components Exposed 

4 to Treated Water, Treated Borated Water, 

5 or Sodium Pentaborate Solution .................... 3.2-16 

6 3.2.3.2.13 Loss of Material Due to Pitting and 

7 Crevice Corrosion in Aluminum Alloys ........... 3.2-17 

8 3.2.3.3 Aging Management Review Results 

9 Not Consistent With or Not Addressed in the 

10 Generic Aging Lessons Learned for 

11 Subsequent License Renewal Report .............................. 3.2-17 

12 3.2.3.4 Aging Management Programs ......................................... 3.2-17 

13 3.2.3.5 Final Safety Analysis Report Supplement ........................ 3.2-18 

14 3.2.4 Evaluation Findings......................................................................... 3.2-18 

15 3.2.5 Implementation ................................................................................ 3.2-19 

16 3.2.6 References ....................................................................................... 3.2-19 

17 3.3 Aging Management of Auxiliary Systems ................................................... 3.3-1 

18 3.3.1 Areas of Review ................................................................................. 3.3-1 

19 3.3.2 Acceptance Criteria ........................................................................... 3.3-2 

20 3.3.2.1 Aging Management Review Results Consistent With 

21 the Generic Aging Lessons Learned for Subsequent 

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

23 3.3.2.2 Aging Management Review Results for Which Further 

24 Evaluation Is Recommended by the Generic Aging 

25 Lessons Learned for Subsequent License 

26 Renewal Report ................................................................. 3.3-2 

27 3.3.2.2.1 Cumulative Fatigue Damage ............................ 3.3-3 

28 3.3.2.2.2 Cracking Due to Stress Corrosion 

29 Cracking and Cyclic Loading ............................ 3.3-3 

30 3.3.2.2.3 Cracking Due to Stress Corrosion Cracking ..... 3.3-3 

31 3.3.2.2.4 Loss of Material Due to Pitting and 

32 Crevice Corrosion ............................................. 3.3-4 

33 3.3.2.2.5 Quality Assurance for Aging Management 

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

35 3.3.2.2.6 Ongoing Review of Operating Experience ....... 3.3-5 

36 3.3.2.2.7 Loss of Material Due to Recurring 

37 Internal Corrosion ............................................. 3.3-5 

38 3.3.2.2.8 Reduction in Impact Strength ........................... 3.3-6 

39 3.3.2.2.9 Cracking Due to Stress Corrosion Cracking 

40 and Intergranular Stress Corrosion Cracking ... 3.3-7 

41 3.3.2.2.10 Cracking Due to Stress Corrosion Cracking 

42 in Aluminum Alloys ........................................... 3.3-7 

43 3.3.2.2.11 Loss of Material Due to General, Crevice 

44 or Pitting Corrosion and Microbiologically45 Induced Corrosion and Cracking Due to 

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

47 3.3.2.2.12 Loss of Material Due to Pitting and Crevice 

48 Corrosion and Microbiologically-Induced 

49 Corrosion in Components Exposed to 

50 Treated Water, Treated Borated Water, or 

51 Sodium Pentaborate Solution ........................... 3.3-9 
xii 

1 3.3.2.2.13 Loss of Material Due to Pitting and 

2 Crevice Corrosion in Aluminum Alloys ........... 3.3-10

3 3.3.2.3 Aging Management Review Results Not Consistent 

4 With or Not Addressed in the Generic Aging Lessons 

5 Learned for Subsequent License Renewal Report .......... 3.3-11 

6 3.3.2.4 Aging Management Programs ......................................... 3.3-11 

7 3.3.2.5 Final Safety Analysis Report Supplement ........................ 3.3-11 

8 3.3.3 Review Procedures.......................................................................... 3.3-12 

9 3.3.3.1 Aging Management Review Results Consistent With 

10 the Generic Aging Lessons Learned for Subsequent 

11 License Renewal Report .................................................. 3.3-12 

12 3.3.3.2 Aging Management Review Results Report for Which 

13 Further Evaluation Is Recommended by the Generic 

14 Aging Lessons Learned for Subsequent License 

15 Renewal Report ............................................................... 3.3-12 

16 3.3.3.2.1 Cumulative Fatigue Damage .......................... 3.3-12 

17 3.3.3.2.2 Cracking Due to Stress Corrosion 

18 Cracking and Cyclic Loading .......................... 3.3-12 

19 3.3.3.2.3 Cracking Due to Stress Corrosion Cracking ... 3.3-13 

20 3.3.3.2.4 Loss of Material Due to Pitting and 

21 Crevice Corrosion ........................................... 3.3-13 

22 3.3.3.2.5 Quality Assurance for Aging Management 

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

24 3.3.3.2.6 Ongoing Review of Operating Experience ..... 3.3-13 

25 3.3.3.2.7 Loss of Material Due to Recurring 

26 Internal Corrosion ........................................... 3.3-14 

27 3.3.3.2.8 Reduction in Impact Strength ......................... 3.3-14 

28 3.3.3.2.9 Cracking Due to Stress Corrosion 

29 Cracking and Intergranular Stress 

30 Corrosion Cracking ......................................... 3.3-14

31 3.3.3.2.10 Cracking Due to Stress Corrosion Cracking 

32 in Aluminum Alloys ......................................... 3.3-15 

33 3.3.3.2.11 Loss of Material Due to General, Crevice 

34 or Pitting Corrosion and Microbiologically35 Induced Corrosion and Cracking Due to 

36 Stress Corrosion Cracking ............................. 3.3-17

37 3.3.3.2.12 Loss of Material Due to Pitting and 

38 Crevice Corrosion and Microbiologically39 Induced Corrosion in Components Exposed 

40 to Treated Water, Treated Borated Water, 

41 or Sodium Pentaborate Solution .................... 3.3-17 

42 3.3.3.2.13 Loss of Material Due to Pitting and Crevice 

43 Corrosion in Aluminum Alloys ........................ 3.3-17

44 3.3.3.3 Aging Management Review Results Not Consistent 

45 With or Not Addressed in the Generic Aging Lessons 

46 Learned for Subsequent License Renewal Report .......... 3.3-18 

47 3.3.3.4 Aging Management Programs ......................................... 3.3-18 

48 3.3.4 Evaluation Findings......................................................................... 3.3-18 

49 3.3.5 Implementation ................................................................................ 3.3-19 

50 3.3.6 References ....................................................................................... 3.3-19
xiii 

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

2 3.4.1 Areas of Review ................................................................................. 3.4-1 

3 3.4.2 Acceptance Criteria ........................................................................... 3.4-2 

4 3.4.2.1 Aging Management Review Results Consistent With 

5 the Generic Aging Lessons Learned for Subsequent 

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

7 3.4.2.2 Aging Management Review Results for Which Further 

8 Evaluation Is Recommended by the Generic Aging 

9 Lessons Learned for Subsequent License 

10 Renewal Report ................................................................. 3.4-2 

11 3.4.2.2.1 Cumulative Fatigue Damage ............................ 3.4-2 

12 3.4.2.2.2 Cracking Due to Stress Corrosion Cracking ..... 3.4-3 

13 3.4.2.2.3 Loss of Material Due to Pitting and 

14 Crevice Corrosion ............................................. 3.4-4 

15 3.4.2.2.4 Quality Assurance for Aging Management of 

16 Nonsafety-Related Components ...................... 3.4-5 

17 3.4.2.2.5 Ongoing Review of Operating Experience ....... 3.4-5 

18 3.4.2.2.6 Loss of Material Due to Recurring 

19 Internal Corrosion ............................................. 3.4-5 

20 3.4.2.2.7 Cracking Due to Stress Corrosion Cracking 

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

22 3.4.2.2.8 Loss of Material Due to General, Crevice 

23 or Pitting Corrosion and Microbiologically24 Induced Corrosion and Cracking Due to Stress 

25 Corrosion Cracking ........................................... 3.4-7 

26 3.4.2.2.9 Loss of Material Due to Pitting and Crevice 

27 Corrosion and Microbiologically-Induced 

28 Corrosion in Components Exposed to Treated 

29 Water, Treated Borated Water, or Sodium 

30 Pentaborate Solution ........................................ 3.4-8 

31 3.4.2.2.10 Loss of Material Due to Pitting and Crevice 

32 Corrosion in Aluminum Alloys .......................... 3.4-9

33 3.4.2.3 Aging Management Review Results Not Consistent 

34 With or Not Addressed in the Generic Aging Lessons 

35 Learned for Subsequent License Renewal Report .......... 3.4-10 

36 3.4.2.4 Aging Management Programs ......................................... 3.4-10 

37 3.4.2.5 Final Safety Analysis Report Supplement ........................ 3.4-10

38 3.4.3 Review Procedures.......................................................................... 3.4-11 

39 3.4.3.1 Aging Management Review Results Consistent With 

40 the Generic Aging Lessons Learned for Subsequent 

41 License Renewal Report .................................................. 3.4-11 

42 3.4.3.2 Aging Management Review Results for Which Further 

43 Evaluation Is Recommended by the Generic Aging 

44 Lessons Learned for Subsequent License 

45 Renewal Report ............................................................... 3.4-11 

46 3.4.3.2.1 Cumulative Fatigue Damage .......................... 3.4-11 

47 3.4.3.2.2 Cracking Due to Stress Corrosion Cracking ... 3.4-11 

48 3.4.3.2.3 Loss of Material Due to Pitting and 

49 Crevice Corrosion ........................................... 3.4-12 

50 3.4.3.2.4 Quality Assurance for Aging Management 

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

1 3.4.3.2.5 Ongoing Review of Operating Experience ..... 3.4-12 

2 3.4.3.2.6 Loss of Material Due to Recurring 

3 Internal Corrosion ........................................... 3.4-13 

4 3.4.3.2.7 Cracking Due to Stress Corrosion Cracking 

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

6 3.4.3.2.8 Loss of Material Due to General, Crevice 

7 or Pitting Corrosion and Microbiologically8 Induced Corrosion and Cracking Due to 

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

10 3.4.3.2.9 Loss of Material Due to Pitting and 

11 Crevice Corrosion and Microbiologically12 Induced Corrosion in Components Exposed 

13 to Treated Water, Treated Borated Water, or 

14 Sodium Pentaborate Solution ......................... 3.4-15 

15 3.4.3.2.10 Loss of Material Due to Pitting and Crevice 

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

17 3.4.3.3 Aging Management Review Results Not Consistent 

18 With or Not Addressed in the Generic Aging Lessons 

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

20 3.4.3.4 Aging Management Programs ......................................... 3.4-16 

21 3.4.3.5 Final Safety Analysis Report Supplement ........................ 3.4-17 

22 3.4.4 Evaluation Findings......................................................................... 3.4-17 

23 3.4.5 Implementation ................................................................................ 3.4-18 

24 3.4.6 References ....................................................................................... 3.4-18 

25 3.5 Aging Management of Containments, Structures, and 

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

27 3.5.1 Areas of Review ................................................................................. 3.5-1 

28 3.5.2 Acceptance Criteria ........................................................................... 3.5-2 

29 3.5.2.1 Aging Management Review Results Consistent With 

30 the Generic Aging Lessons Learned for Subsequent 

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

32 3.5.2.2 Aging Management Review Results for Which Further 

33 Evaluation Is Recommended by the Generic Aging 

34 Lessons Learned for Subsequent License 

35 Renewal Report ................................................................. 3.5-2 

36 3.5.2.2.1 Pressurized Water Reactor and Boiling Water 

37 Reactor Containments ...................................... 3.5-3 

38 3.5.2.2.2 Safety-Related and Other Structures and 

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

40 3.5.2.2.3 Quality Assurance for Aging Management 

41 of Nonsafety-Related Components .................. 3.5-7 

42 3.5.2.2.4 Ongoing Review of Operating Experience ....... 3.5-7

43 3.5.2.3 Aging Management Review Results Not Consistent 

44 With or Not Addressed in the Generic Aging Lessons 

45 Learned for Subsequent License Renewal Report ............ 3.5-7 

46 3.5.2.4 Aging Management Programs ........................................... 3.5-7 

47 3.5.2.5 Final Safety Analysis Report Supplement .......................... 3.5-8 

48 3.5.3 Review Procedures............................................................................ 3.5-8 

49 3.5.3.1 Aging Management Review Results Consistent With 

50 the Generic Aging Lessons Learned for Subsequent 

51 License Renewal Report .................................................... 3.5-8 
xv 

1 3.5.3.2 Aging Management Review Results for Which Further 

2 Evaluation Is Recommended by the Generic Aging 

3 Lessons Learned for Subsequent License 

4 Renewal Report ................................................................. 3.5-9 

5 3.5.3.2.1 Pressurized Water Reactor and Boiling 

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

7 3.5.3.2.2 Safety-Related and Other Structures, and 

8 Component Supports ..................................... 3.5-12 

9 3.5.3.2.3 Quality Assurance for Aging Management 

10 of Nonsafety-Related Components ................ 3.5-16 

11 3.5.3.2.4 Ongoing Review of Operating Experience ..... 3.5-16 

12 3.5.3.3 Aging Management Review Results Not Consistent 

13 With or Not Addressed in the Generic Aging Lessons 

14 Learned for Subsequent License Renewal Report .......... 3.5-16 

15 3.5.3.4 Aging Management Programs ......................................... 3.5-16 

16 3.5.3.5 Final Safety Analysis Report Supplement ........................ 3.5-17 

17 3.5.4 Evaluation Findings......................................................................... 3.5-17 

18 3.5.5 Implementation ................................................................................ 3.5-18 

19 3.5.6 References ....................................................................................... 3.5-18 

20 3.6 Aging Management of Electrical and Instrumentation and Controls ....... 3.6-1 

21 3.6.1 Areas of Review ................................................................................. 3.6-1 

22 3.6.2 Acceptance Criteria ........................................................................... 3.6-1 

23 3.6.2.1 Aging Management Review Results Consistent With 

24 the Generic Aging Lessons Learned for Subsequent 

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

26 3.6.2.2 Aging Management Review Results for Which Further 

27 Evaluation Is Recommended by the Generic Aging 

28 Lessons Learned for Subsequent License 

29 Renewal Report ................................................................. 3.6-2 

30 3.6.2.2.1 Electrical Equipment Subject to 

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

32 3.6.2.2.2 Reduced Insulation Resistance Due to Loss 

33 of Material Due to General, Pitting, and 

34 Crevice Corrosion, Loosening of Bolts 

35 Caused by Thermal Cycling and Ohmic 

36 Heating, Degradation Caused 

37 Thermal/Thermoxidative Degradation of 

38 Organics and Photolysis (UV Sensitive 

39 Materials Only) of Organics, Moisture/Debris 

40 Intrusion and Ohmic Heating ............................ 3.6-2

41 3.6.2.2.3 Loss of Material Due to Wind-Induced 

42 Abrasion, Loss of Conductor Strength Due to 

43 Corrosion, and Increased Resistance of 

44 Connection Due to Oxidation or 

45 Loss of Preload ................................................ 3.6-3 

46 3.6.2.2.4 Quality Assurance for Aging Management 

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

48 3.6.2.2.5 Ongoing Review of Operating Experience ....... 3.6-3 

49 3.6.2.3 Aging Management Review Results Not Consistent 

50 With or Not Addressed in the Generic Aging Lessons 

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

1 3.6.2.4 Aging Management Programs ........................................... 3.6-3 

2 3.6.2.5 Final Safety Analysis Review Supplement ......................... 3.6-4 

3 3.6.3 Review Procedures............................................................................ 3.6-4 

4 3.6.3.1 Aging Management Review Results Consistent With 

5 the Generic Aging Lessons Learned for Subsequent 

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

7 3.6.3.2 Aging Management Review Results for Which Further 

8 Evaluation Is Recommended by the Generic Aging 

9 Lessons Learned for Subsequent License 

10 Renewal Report ................................................................. 3.6-4 

11 3.6.3.2.1 Electrical Equipment Subject to 

12 Environmental Qualification .............................. 3.6-4 

13 3.6.3.2.2 Reduced Insulation Resistance Due to 

14 Loss of Material Due to General, Pitting, 

15 and Crevice Corrosion, Loosening of Bolts 

16 Caused by Thermal Cycling and Ohmic Heating, 

17 Degradation Caused by Thermal/Thermoxidative 

18 Degradation of Organics and Photolysis 

19 (UV Sensitive Materials Only) of 

20 Organics, Moisture/Debris Intrusion and 

21 Ohmic Heating .................................................. 3.6-5 

22 3.6.3.2.3 Loss of Material Due to Wind-Induced 

23 Abrasion, Loss of Conductor Strength Due to 

24 Corrosion, and Increased Resistance of 

25 Connection Due to Oxidation or 

26 Loss of Preload ................................................ 3.6-5 

27 3.6.3.2.4 Quality Assurance for Aging Management 

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

29 3.6.3.2.5 Ongoing Review of Operating Experience ....... 3.6-5 

30 3.6.3.3 Aging Management Review Results Not Consistent 

31 With or Not Addressed in the Generic Aging Lessons 

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

33 3.6.3.4 Aging Management Programs ........................................... 3.6-6 

34 3.6.3.5 Final Safety Analysis Report Supplement .......................... 3.6-6 

35 3.6.4 Evaluation Findings........................................................................... 3.6-7 

36 3.6.5 Implementation .................................................................................. 3.6-7 

37 3.6.6 References ......................................................................................... 3.6-7

38 4 TIME-LIMITED AGING ANALYSES ........................................................................... 4.1-1 

39 4.1 Identification of Time-Limited Aging Analyses and Exemptions.............. 4.1-1 

40 4.1.1 Areas of Review ................................................................................. 4.1-1 

41 4.1.2 Acceptance Criteria ........................................................................... 4.1-1 

42 4.1.3 Review Procedures............................................................................ 4.1-3 

43 4.1.4 Evaluation Findings........................................................................... 4.1-5 

44 4.1.5 Implementation .................................................................................. 4.1-5 

45 4.1.6 References ......................................................................................... 4.1-5 

46 4.2 Reactor Pressure Vessel Neutron Embrittlement Analysis....................... 4.2-1 

47 4.2.1 Areas of Review ................................................................................. 4.2-1 

48 4.2.2 Acceptance Criteria ........................................................................... 4.2-1 

49 4.2.2.1 Time-Limited Aging Analysis .............................................. 4.2-1 

50 4.2.2.1.1 Neutron Fluence ............................................... 4.2-2 
xvii 

1 4.2.2.1.2 Upper-Shelf Energy .......................................... 4.2-3 

2 4.2.2.1.3 Pressurized Thermal Shock (for PWRs) .......... 4.2-3 

3 4.2.2.1.4 Pressure-Temperature Limits ........................... 4.2-4

4 4.2.2.1.5 Elimination of Boiling Water Reactor 

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

6 4.2.2.1.6 BWR Axial Welds ............................................. 4.2-6 

7 4.2.2.2 Final Safety Analysis Report Supplement .......................... 4.2-6 

8 4.2.3 Review Procedures............................................................................ 4.2-6 

9 4.2.3.1 Time-Limited Aging Analysis .............................................. 4.2-6 

10 4.2.3.1.1 Neutron Fluence ............................................... 4.2-6 

11 4.2.3.1.2 Upper-Shelf Energy .......................................... 4.2-7 

12 4.2.3.1.3 Pressurized Thermal Shock (for PWRs) .......... 4.2-8 

13 4.2.3.1.4 Pressure-Temperature Limits ......................... 4.2-11 

14 4.2.3.1.5 Elimination of Boiling Water Reactor 

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

16 4.2.3.1.6 Boiling Water Reactor Axial Welds ................. 4.2-13 

17 4.2.3.2 Final Safety Analysis Report Supplement ........................ 4.2-13 

18 4.2.4 Evaluation Findings......................................................................... 4.2-14 

19 4.2.5 Implementation ................................................................................ 4.2-14 

20 4.2.6 References ....................................................................................... 4.2-14 

21 4.3 Metal Fatigue ................................................................................................. 4.3-1 

22 4.3.1 Area of Review ................................................................................... 4.3-1 

23 4.3.2 Acceptance Criteria ........................................................................... 4.3-2 

24 4.3.2.1 Time-Limited Aging Analysis .............................................. 4.3-2 

25 4.3.2.1.1 Components Evaluated for Fatigue 

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

27 4.3.2.1.2 Components Evaluated for CUFen .................... 4.3-3 

28 4.3.2.2 Final Safety Analysis Report Supplement .......................... 4.3-4 

29 4.3.3 Review Procedures............................................................................ 4.3-5 

30 4.3.3.1 Time-Limited Aging Analysis .............................................. 4.3-5 

31 4.3.3.1.1 Components Evaluated for Fatigue 

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

33 4.3.3.1.2 Components Evaluated for CUFen .................... 4.3-6 

34 4.3.3.2 Final Safety Analysis Report Supplement .......................... 4.3-8 

35 4.3.4 Evaluation Findings........................................................................... 4.3-8 

36 4.3.5 Implementation .................................................................................. 4.3-9 

37 4.3.6 References ......................................................................................... 4.3-9 

38 4.4 Environmental Qualification (EQ) of Electric Equipment .......................... 4.4-1 

39 4.4.1 Areas of Review ................................................................................. 4.4-1 

40 4.4.1.1 Time-Limited Aging Analysis .............................................. 4.4-2 

41 4.4.1.1.1 Division of Operating Reactors Guidelines ....... 4.4-2 

42 4.4.1.1.2 NUREG–0588, Category II 

43 (IEEE STD 323-1971) ...................................... 4.4-2 

44 4.4.1.1.3 NUREG–0588, Category I 

45 (IEEE STD 323-1974) ...................................... 4.4-2 

46 4.4.1.2 Generic Safety Issue .......................................................... 4.4-3 

47 4.4.1.3 Final Safety Analysis Report Supplement .......................... 4.4-3 

48 4.4.2 Acceptance Criteria ........................................................................... 4.4-3 

49 4.4.2.1 Time-Limited Aging Analysis .............................................. 4.4-3 

50 4.4.2.1.1 10 CFR 54.21(c)(1)(i) ....................................... 4.4-4 

51 4.4.2.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.4-4 
xviii 

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

2 4.4.2.2 Final Safety Analysis Report Supplement .......................... 4.4-4 

3 4.4.3 Review Procedures............................................................................ 4.4-5 

4 4.4.3.1 Time-Limited Aging Analysis .............................................. 4.4-5 

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

6 4.4.3.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.4-5 

7 4.4.3.1.3 10 CFR 54.21(c)(1)(iii) ...................................... 4.4-5 

8 4.4.3.2 Final Safety Analysis Report Supplement .......................... 4.4-6 

9 4.4.4 Evaluation of Findings ...................................................................... 4.4-6 

10 4.4.5 Implementation .................................................................................. 4.4-6 

11 4.4.6 References ......................................................................................... 4.4-7 

12 4.5 Concrete Containment Unbonded Tendon Prestress Analysis .................. 4.5-1 

13 4.5.1 Areas of Review ................................................................................. 4.5-1 

14 4.5.2 Acceptance Criteria ........................................................................... 4.5-1 

15 4.5.2.1 Time-Limited Aging Analysis .............................................. 4.5-1 

16 4.5.2.1.1 10 CFR 54.21(c)(1)(i) ....................................... 4.5-1 

17 4.5.2.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.5-2 

18 4.5.2.1.3 10 CFR 54.21(c)(1)(iii) ...................................... 4.5-2 

19 4.5.2.2 Final Safety Analysis Report Supplement .......................... 4.5-2 

20 4.5.3 Review Procedures............................................................................ 4.5-3 

21 4.5.3.1 Time-Limited Aging Analysis .............................................. 4.5-3 

22 4.5.3.1.1 10 CFR 54.21(c)(1)(i) ....................................... 4.5-3 

23 4.5.3.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.5-3 

24 4.5.3.1.3 10 CFR 54.21(c)(1)(iii) ...................................... 4.5-3 

25 4.5.3.2 Final Safety Analysis Report Supplement .......................... 4.5-4 

26 4.5.4 Evaluation Findings........................................................................... 4.5-4 

27 4.5.5 Implementation .................................................................................. 4.5-5 

28 4.5.6 References ......................................................................................... 4.5-5 

29 4.6 Containment Liner Plate, Metal Containments, and Penetrations 

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

31 4.6.1 Areas of Review ................................................................................. 4.6-1 

32 4.6.1.1 Time-Limited Aging Analysis 

33 (Fatigue Parameter Evaluations) ....................................... 4.6-2 

34 4.6.1.1.1 Fatigue Analyses (ASME Section III, 

35 MC or Class 1) ................................................. 4.6-2 

36 4.6.1.1.2 Fatigue Waiver Evaluations .............................. 4.6-3 

37 4.6.1.2 Final Safety Analysis Report Supplement .......................... 4.6-3 

38 4.6.2 Acceptance Criteria ........................................................................... 4.6-3 

39 4.6.2.1 Time-Limited Aging Analysis .............................................. 4.6-3 

40 4.6.2.1.1 Fatigue Parameter Evaluations ........................ 4.6-4 

41 4.6.2.2 Final Safety Analysis Report Supplement .......................... 4.6-5 

42 4.6.3 Review Procedures............................................................................ 4.6-5 

43 4.6.3.1 Time-Limited Aging Analysis .............................................. 4.6-5 

44 4.6.3.1.1 Fatigue Parameter Evaluations ........................ 4.6-5 

45 4.6.3.2 Final Safety Analysis Report Supplement .......................... 4.6-6 

46 4.6.4 Evaluation Findings........................................................................... 4.6-6 

47 4.6.5 Implementation .................................................................................. 4.6-7 

48 4.6.6 References ......................................................................................... 4.6-7 

49 4.7 Other Plant-Specific Time-Limited Aging Analyses ................................... 4.7-1 

50 4.7.1 Areas of Review ................................................................................. 4.7-1 

51 4.7.1.1 Time-Limited Aging Analysis .............................................. 4.7-2 
xix 

1 4.7.1.2 Final Safety Analysis Report Supplement .......................... 4.7-2 

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

3 4.7.2.1 Time-Limited Aging Analysis .............................................. 4.7-2 

4 4.7.2.1.1 10 CFR 54.21(c)(1)(i) ....................................... 4.7-2 

5 4.7.2.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.7-2 

6 4.7.2.1.3 10 CFR 54.21(c)(1)(iii) ...................................... 4.7-2 

7 4.7.2.2 Final Safety Analysis Report Supplement .......................... 4.7-3 

8 4.7.3 Review Procedures............................................................................ 4.7-3 

9 4.7.3.1 Time-Limited Aging Analysis .............................................. 4.7-3 

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

11 4.7.3.1.2 10 CFR 54.21(c)(1)(ii) ...................................... 4.7-4 

12 4.7.3.1.3 10 CFR 54.21(c)(1)(iii) ...................................... 4.7-4 

13 4.7.3.2 Final Safety Analysis Report Supplement .......................... 4.7-4 

14 4.7.4 Evaluation Findings........................................................................... 4.7-5 

15 4.7.5 Implementation .................................................................................. 4.7-5 

16 4.7.6 References ......................................................................................... 4.7-5 

17 5 TECHNICAL SPECIFICATIONS CHANGES ................................................................ 5-1 

18 5.1 Review of Technical Specifications Changes and Additions 

19 Necessary to Manage the Effects of Aging During the Subsequent 

20 Period of Extended Operation ......................................................................... 5-1 

21 5.1.1 Areas of Review .................................................................................... 5-1 

22 5.1.2 Acceptance Criteria .............................................................................. 5-1 

23 5.1.3 Review Procedures............................................................................... 5-2 

24 5.1.4 Evaluation Findings.............................................................................. 5-3 

25 5.1.5 Implementation ..................................................................................... 5-3 

26 5.1.6 References ............................................................................................ 5-3 

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

xxi 

1 LIST OF TABLES 

2 Table Page 

3 1.1-1 Acceptance Review Checklist for Subsequent License Renewal Application 

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

5 2.1-1 Sample Listing of Potential Information Sources .................................................. 2.1-12 

6 2.1-2 Specific Staff Guidance on Scoping ..................................................................... 2.1-13 

7 2.1-3 Specific Staff Guidance on Screening .................................................................. 2.1-15 

8 2.1-4(a) Typical “Passive” Structure-Intended Functions ................................................... 2.1-16 

9 2.1-4(b) Typical “Passive” Component-Intended Functions ............................................... 2.1-17 

10 2.1-5 Typical Structures, Components, and Commodity Groups, and 

11 10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment .............. 2.1-18 

12 2.2-1 Examples of System and Structure Scoping and Basis for Disposition .................. 2.2-5 

13 2.3-1 Examples of Mechanical Components Scoping and Basis for Disposition ............. 2.3-6 

14 2.3-2 Examples of Mechanical Components Screening and Basis for Disposition ......... 2.3-7 

15 2.3-3 Examples of Mechanical Component-Intended Functions ..................................... 2.3-8 

16 2.4-1 Examples of Structural Components Scoping/Screening and Basis 

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

18 2.5-1 Examples of “Plant Spaces” Approach for Electrical and I&C Scoping and 

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

20 3.0-1 FSAR Supplement for Aging Management of Applicable Systems for SLR ........... 3.0-8 

21 3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, 

22 and Reactor Coolant System Evaluated in Chapter IV of the 

23 GALL-SLR Report ................................................................................................ 3.1-29 

24 3.1-2 Aging Management Programs and Additional Guidance Appendices 

25 Recommended for Reactor Vessel, Internals, and Reactor Coolant System ....... 3.1-58 

26 3.2-1 Summary of Aging Management Programs for Engineered Safety Features 

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

28 3.2-2 AMPs and Additional Guidance Appendices Recommended for Aging 

29 Management of Engineered Safety Features ....................................................... 3.2-40 

30 3.3-1 Summary of Aging Management Programs for Auxiliary Systems Evaluated 

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

32 3.3-2 AMPs and Additional Guidance Appendices Recommended for Aging 

33 Management of Auxiliary Systems ....................................................................... 3.3-68 

34 3.4-1 Summary of Aging Management Programs for Steam and Power 

35 Conversion System Evaluated in Chapter VIII of the GALL-SLR Report ............. 3.4-19 

36 3.4-2 AMPs and Additional Guidance Appendices Recommended for Aging 

37 Management of Steam and Power Conversion System ....................................... 3.4-42 

38 3.5-1 Summary of Aging Management Programs for Containments, Structures 

39 and Component Supports Evaluated in Chapters II and III of the 

40 GALL-SLR Report ................................................................................................ 3.5-20 

41 3.5-2 AMPs and Additional Guidance Appendices Recommended for 

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

43 3.6-1 Summary of Aging Management Programs for the Electrical Components 

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

45 3.6-2 AMPs and Additional Guidance Appendices Recommended for Electrical 

46 and Instrumentation and Control Systems ........................................................... 3.6-18
xxii 

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

2 (TLAA) and Basis for Disposition ............................................................................ 4.1-6 

3 4.1-2 Generic Time-Limited Aging Analyses ................................................................. 4.1-10 

4 4.2-1 Examples of FSAR Supplement for Reactor Vessel Neutron 

5 Embrittlement Analyses ........................................................................................ 4.2-17 

6 4.3-1 Examples of FSAR Supplement for Metal Fatigue TLAA Evaluation ................... 4.3-10 

7 4.4-1 Environmental Qualification Reanalysis Attributes ................................................. 4.4-9 

8 4.4-2 Examples of FSAR Supplement for Environmental Qualification Electric 

9 Equipment TLAA Evaluation ................................................................................. 4.4-12 

10 4.5-1 Examples of FSAR Supplement for Concrete Containment Tendon 

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

12 4.6-1 Examples of FSAR Supplement for Containment Liner Plates, Metal 

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

14 4.7-1 Examples of Potential Plant-Specific TLAA Topics ................................................ 4.7-6 

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

16 License Renewal ................................................................................................. A.1-10 
xxiii 

LIST OF CONTRIBUTORS1

Division of License Renewal, Office of Nuclear Reactor Regulation 

B. Holian Division Director 

C. Miller Division Director 

J. Lubinski Division Director 

R. Cadwell Deputy Division Director 

M. Delligatti Deputy Division Director 

M. Galloway Deputy Division Director 

J. Marshall Deputy Division Director 

S. Weerakkody Deputy Division Director 

 

S. Bloom Branch Chief 

Y. Diaz-Sanabria Branch Chief 

M. Marshall Branch Chief 

D. Morey Branch Chief 

B. Pham Branch Chief 

 

A. Hiser Senior Technical Advisor 

 

B. Brady Technical Project Manager Lead 

 

W. Burton Regulatory Project Manager Lead 

 

A. Billoch Lead Project Manager 

H. Jones Lead Project Manager 

J. Mitchell Lead Project Manager 

R. Plasse Lead Project Manager 

B. Rogers Lead Project Manager 

E. Sayoc Lead Project Manager 

 

E. Gettys Public Coordination 

 

A. Bufford Structural Engineering 

D. Brittner Project Manager 

C. Doutt Electrical Engineering 

B. Fu Mechanical Engineering 

 

1

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

current position. 
xxiv 

W. Gardner Mechanical Engineering 

J. Gavula Mechanical Engineering 

B. Grange Project Manager 

K. Green Mechanical Engineering 

W. Holston Mechanical Engineering 

C. Hovanec Mechanical Engineering 

R. Kalikian Mechanical Engineering 

B. Litkett Project Manager 

J. Medoff Mechanical Engineering 

S. Min Mechanical Engineering 

A. Prinaris Structural Engineering 

M. Sadollah Structural Engineering 

G. Thomas Structural Engineering 

M. Yoo Mechanical Engineering 

 

Office of Nuclear Reactor Regulation

D. Alley Branch Chief 

S. Bailey Branch Chief 

R. Dennig Branch Chief 

C. Jackson Branch Chief 

A. Klein Branch Chief 

G. Kulesa Branch Chief 

T. Lupold Branch Chief 

S. Rosenberg Branch Chief 

J. Zimmerman Branch Chief 

 

R. Hardies Senior Level Advisor 

K. Karwoski Senior Level Advisor 

 

L. Banic Project Manager 

G. Cheruvenki Materials Engineering 

J. Collins Materials Engineering 

S. Cumblidge Materials Engineering 

A. Erickson Structural Engineering 

C. Fairbanks Materials Engineering 

M. Hardgrove Mechanical Engineering 

K. Hoffman Materials Engineering 

A. Johnson Reactor Operations Engineering 

S. Jones Reactor Systems Engineering 

B. Lee Reactor Systems Engineering 

B. Lehman Structural Engineering 

R. Mathew Electrical Engineering 
xxv 

I. Naeem Fire Protection Engineer 

C. Ng Mechanical Engineering 

D. Nguyen Electrical Engineering 

A. Obodoako Materials Engineer 

B. Parks Reactor Engineering 

J. Poehler Materials Engineering 

P. Purtscher Materials Engineering 

S. Ray Electrical Engineering 

S. Sheng Materials Engineering 

A. Tsirigotis Mechanical Engineer 

P. Verdi Foreign Assignee 

O. Yee Reactor Systems Engineering 

M. Yoder Chemical Engineering 

 

Region II

P. Cooper Sr. Reactor Inspector

J. Rivera-Ortiz Reactor Inspector 

 

Region III

N. Feliz-Adorno Sr. Reactor Inspector 

M. Holmberg Sr. Reactor Inspector 

C. Tilton Sr. Reactor Inspector 

 

Region IV

S. Graves Sr. Reactor Inspector 

G. Pick Sr. Reactor Inspector 

M. Williams Reactor Inspector 

 

Office of New Reactors

J. Xu Branch Chief 

A. Istar Structural Engineering 

 

Office of Nuclear Materials and Safeguards

A. Csontos Branch Chief

J. Wise Materials Engineering

 

Office of Nuclear Regulatory Research

J. Burke Branch Chief 

S. Frankl Branch Chief 

M. Gavrilas Branch Chief 

J. Nakoski Branch Chief 

W. Ott Branch Chief 
xxvi 

D. Rudland Branch Chief 

M. Salley Branch Chief 

R. Sydnor Branch Chief 

J. Ake Senior Technical Advisor—Geophysical Engineering 

T. Nicholson Senior Technical Advisor—Radionuclide Transport 

R. Tregoning Senior Technical Advisor—Materials Engineering 

A. Hull Team Leader 

K. Arai Materials Engineering 

M. Benson Materials Engineering 

H. Candra Structural Engineering 

E. Focht Materials Engineering 

M. Fuhrman Geochemistry 

C. Harris Materials Engineering 

M. Hiser Materials Engineering 

M. Homiack Mechanical Engineering 

M. Kirk Materials Engineering 

B. Lin Mechanical Engineering 

S. Malik Materials Engineering 

K. Miller Electrical Engineering 

W. Norris Materials Engineering 

G. Oberson Materials Engineering 

R. Perkins Reliability & Risk Engineering 

I. Prokofiev Materials Engineering 

J. Philip Geotechnical Engineering 

A. Pulvirenti Materials Engineering 

S. Rao Materials Engineering 

M. Rossi Materials Engineering 

M. Sircar Structural Engineering 

M. Srinivasan Materials Engineering 

G. Stevens Materials Engineering 

D. Stroup Fire Protection Engineering 

J. Wallace Materials Engineering 

G. Wang Mechanical Engineering 

Center for Nuclear Waste Regulatory Analyses

G. Adams Computer Scientist/Industrial Engineering 

L. Howard Project Manager/Nuclear Engineering 

L. Naukam Program Support/Technical Editing 

Y. Pan Materials Engineering 

A. Ramos Program Support/Technical Editing 
xxvii 

ABBREVIATIONS 

ACI American Concrete Institute 

AFW auxiliary feedwater 

AMPs aging management programs 

AMR aging management review 

ANSI American National Standards Institute 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

ATWS anticipated transients without scram 

 

B&PV Boiler and Pressure Vessel 

B&W Babcock & Wilcox 

BWR boiling water reactor 

BWRVIP Boiling Water Reactor Vessel and Internals Project 

 

CASS cast austenitic stainless steel 

CDF core damage frequency 

CE Combustion Engineering 

CFR Code of Federal Regulations 

CLB current licensing basis 

CRD control rod drive 

CRDM control rod drive mechanism 

CUF cumulative usage factor 

 

DBA design basis accident 

DBEs 

DE 

design basis events 

Division of Engineering 

DG 

DIRS 

Draft Regulatory Guide 

Division of Inspection and Regional Support 

DLR Division of License Renewal 

DOR 

DORL 

DPR 

DSS 

Division of Operating Reactors 

Division of Operating Reactor Licensing 

Division of Policy and Rulemaking 

Division of Safety Systems 

 

ECCS emergency core cooling system 

EDG emergency diesel generator 

EFPY effective full power year 

EMA equivalent margins analysis 

EOL end-of-life 

EPRI Electric Power Research Institute 

EPU extended power uprate 

EQ Environmental Qualification 

 

FAC flow-accelerated corrosion 

FE further evaluation 

FMECA failure modes, effects, and criticality analysis 

FR Federal Register 

FRN Federal Register Notice 

FSAR Final Safety Analysis Report 

FSER Final Safety Evaluation Report 
xxviii 

GALL Generic Aging Lessons Learned 

GALL-SLR Generic Aging Lessons Learned for Subsequent License Renewal 

GE General Electric 

GL generic letter 

GSI generic safety issue 

 

HELB high-energy line break 

HPCI high-pressure coolant injection 

HPSI high-pressure safety injection 

HVAC heating, ventilation, and air conditioning 

 

I&C instrumentation and control 

IASCC Irradiation-assisted stress corrosion cracking 

IEEE Institute of Electrical and Electronics Engineers 

IGSCC intergranular stress corrosion cracking 

IN information notice 

INPO Institute of Nuclear Power Operations 

IPA integrated plant assessment 

IPE individual plant examination 

IPEEE individual plant examination of external events 

ISI inservice inspection 

ISG interim staff guidance 

 

LBB leak-before-break 

LCOs limiting conditions of operations 

LER licensee event report 

LOCA loss of coolant accident 

LRAs license renewal applications 

LWR light-water reactor 

 

MEB metal enclosed bus 

MIC microbiologically-induced corrosion 

MRP Materials Reliability Program 

NEI Nuclear Energy Institute 

NPS nominal pipe size 

NRC U.S. Nuclear Regulatory Commission 

NRR Office of Nuclear Reactor Regulation 

 

ODSCC outside diameter stress corrosion cracking 

OE operating experience 

P&ID piping and instrumentation diagram 

PH precipitation-hardened 

PM Project Manager 

P-T pressure-temperature 

PTLRs pressure-temperature limit reports 

PTS pressurized thermal shock 

PVC polyvinyl chloride 

PWR pressurized water reactor 

PWSCC primary water stress corrosion cracking 

 
xxix 

QA quality assurance 

RAI request for additional information 

RG Regulatory Guide 

RPV reactor pressure vessel 

RT reference temperature 

RTD resistance temperature detector 

RVI reactor vessel internal 

 

SBO station blackout 

SC structures and components 

SCC stress corrosion cracking 

SEEIN Significant Event Evaluation and Information Network 

SEs safety evaluations 

SER safety evaluation report 

SG steam generator 

S/G standards and guides 

SLR subsequent license renewal 

SLRA subsequent license renewal application 

SOC statements of consideration 

SOER significant operating experience report 

SRM staff requirements memorandum 

SRP standard review plan 

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

Applications for Nuclear Power Plants 

SS stainless steel 

SSCs systems, structures, and components 

SSE safe shutdown earthquake 

 

TC thermocouples (nozzles) 

TGSCC transgranular stress corrosion cracking 

TLAAs time-limited aging analysis 

TR topical report 

TS Technical Specifications 

 

UFSAR updated final safety analysis report 

USAR updated safety analysis report 

USE upper-shelf energy 

UV ultraviolet 

 

xxxi 

1 INTRODUCTION 

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

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

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

5 safety reviews of applications to renew nuclear power plant licenses in accordance with 

6 Title 10 of the Code of Federal Regulations (10 CFR) Part 54. The NRC regulations in 

7 10 CFR 54.29 establish the standards for issuance of a renewed license. For nuclear power 

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

9 renewed license may be subsequently renewed in accordance with all applicable 

10 requirements.” The NRC has stated that the requirements for subsequent renewal “include the 

11 provisions of part 54 (unless the Commission subsequently adopts special provisions applicable 

12 only to subsequent renewals).” Statement of Consideration, “Nuclear Power Plant License 

13 Renewal,” 56 FR 64,943, 64,964-65 (Dec. 13, 1991). To date, the NRC has not adopted special 

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

15 continues to govern subsequent license renewal. 

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

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

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

19 make regulatory information widely available to enhance communication with interested 

20 members of the public and the nuclear power industry and to improve their understanding of the 

21 NRC staff review process. 

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

23 subsequent license renewal application (SLRA). The NRC regulation in 10 CFR 54.4 defines 

24 what is within the scope of the license renewal rule. The NRC regulation in 10 CFR 54.21 

25 requires each application to include an integrated plant assessment (IPA), current licensing 

26 basis (CLB) changes during review of the application by the NRC, an evaluation of time-limited 

27 aging analyses (TLAAs), and a Final Safety Analysis Report (FSAR) supplement. 

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

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

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

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

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

33 and (ii) whether any changes made to the plant’s CLB to comply with 10 CFR Part 54 are in 

34 accordance with the Atomic Energy Act of 1954 and NRC regulations. The technical 

35 information to be supplied in the SLRA is specified in 10 CFR 54.21. 

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

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

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

39 structures and components (SCs) that are within the scope of subsequent license renewal and 

40 that require an aging management review (AMR)] and (ii) evaluate TLAAs. The SLRA is the 

41 principal document in which the applicant provides the information needed to understand the 

42 basis upon which the applicant has made this assurance. 

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

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

45 conditions under which existing programs are considered adequate to manage identified aging 
xxxii 

1 effects without change and (ii) the conditions under which existing programs should be 

2 augmented for this purpose. The SRP-SLR also includes the NRC staff’s resolutions of License 

3 Renewal Interim Staff Guidance (LR-ISG) from 2011 through 2013 as listed below. The NRC 

4 issued a draft ISG-2015-01 for public comment on June 29, 2015 (ADAMS No. ML15125A377). 

5 The staff is in the final process of reviewing the ISG for issuance as a final document. Upon 

6 issuance, the changes to aging management program (AMP) XI.M41, “Buried and Underground 

7 Piping and Tanks,” will be incorporated into the GALL- SLR Report and the associated section 

8 of the SRP- SLR. Under the LR-ISG process the NRC staff, industry, or stakeholders can 

9 propose a change to certain license renewal guidance documents. The NRC staff evaluates the 

10 issue, develops proposed interim staff guidance (ISG), and issues an ISG for public comment. 

11 The NRC reviews any comments received, and, as appropriate, issues a final ISG. The ISG is 

12 then used until the NRC staff incorporates it into a formal license renewal guidance 

13 document revision. 

14  LR–ISG–2011–01: Aging Management of Stainless Steel Structures and Components 

15 in Treated Borated Water, Revision 1 

16  LR–ISG–2011–02: Aging Management Program for Steam Generators 

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

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

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

20 Components of Pressurized Water Reactors 

21  LR–ISG–2011–05: Ongoing Review of Operating Experience 

22  LR–ISG–2012–01: Wall Thinning Due to Erosion Mechanisms 

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

24 Atmospheric Storage Tanks, and Corrosion Under Insulation 

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

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

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

28 Recommendations 

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

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

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

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

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

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

35 and evaluated in the GALL-SLR Report, if they rely on the report for subsequent license 

36 renewal (SLR). 
xxxiii 

1 The SRP-SLR is divided into five major chapters: 

2 Chapter 1—Administrative Information 

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

4 Subject to Aging Management Review and Implementation Results 

5 Chapter 3—Aging Management Review Results 

6 Chapter 4—Time-Limited Aging Analyses 

7 Chapter 5—Technical Specifications Changes and Additions 

8 The appendices to the SRP-SLR list branch technical positions. The SRP-SLR addresses 

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

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

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

12 appropriate for the application. In some cases, the major portion of the review of a plant 

13 program or activity may be conducted on a generic basis (with the owners’ group of that plant 

14 type) rather than in the context of reviews of particular applications from utilities. In other cases, 

15 a plant program or activity may be sufficiently similar to that of a previous plant that a complete 

16 review of the program or activity is not needed. For these and similar reasons, reviewers need 

17 not carry out in detail all of the review steps listed in each SRP-SLR section in the review of 

18 every application. 

19 The individual SRP-SLR sections address (i) which organization within the NRC staff are to 

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

21 (v) the conclusions from the review. One of the objectives of the SRP-SLR is to assign review 

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

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

24 branch may require support; the branches assigned these secondary review responsibilities 

25 also are identified for each SRP-SLR section. 

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

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

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

29 1. Areas of Review 

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

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

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

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

34 permit the primary review branch to complete its review. 

35 2. Acceptance Criteria 

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

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

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

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

2 technical positions. 

3 Consistent with the approach described in Generic Aging Lessons Learned for Subsequent 

4 License Renewal (GALL-SLR) Report, the technical bases for some sections of the SRP-SLR 

5 can be provided in branch technical positions or appendices as they are developed and can be 

6 included in the SRP-SLR. 

7 3. Review Procedures 

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

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

10 have been met. 

11 4. Evaluation Findings 

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

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

14 adequately identified the aging effects and the aging management programs credited with 

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

16 evaluation report (SER), in which the reviewers present the results of their review. The SER 

17 also contains a description of the review, including which aspects of the review were selected or 

18 emphasized; which matters were modified by the applicant, required additional information, 

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

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

21 SRP-SLR or exemptions from the regulations. 

22 5. Implementation 

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

24 6. References 

25 This subsection lists the references used in the review process. 

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

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

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

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

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

31 errors, to reflect changes in relevant regulations, and to incorporate modifications approved by 

32 the NRR Director. A revision number and publication date is printed in the lower corner of each 

33 page of each SRP-SLR section. Because individual sections will be revised as needed, the 

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

1 1 ADMINISTRATIVE INFORMATION

2 1.1 Docketing of Timely and Sufficient Renewal Application 

3 Review Responsibilities 

4 Primary—Program responsible for subsequent license renewal projects 

5 Secondary—Branches responsible for technical review, as appropriate 

6 1.1.1 Areas of Review 

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

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

9 (10 CFR) 2.101 and the requirements of 10 CFR Part 54 and (ii) whether an application is timely 

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

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

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

13 determination on the subsequent license renewal application (SLRA). 

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

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

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

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

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

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

20 During this time, and until a license renewal determination has been made by the NRC, the 

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

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

23 if the NRC staff approves the aging management activities provided in the renewal application 

24 before the NRC makes a final determination on the SLRA, the approved applicant may conduct 

25 aging management activities during the timely renewal period using the aging management 

26 programs (AMPs) included in the SLRA. 

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

28 SLRA are reviewed. 

29 1.1.1.1 Docketing and Sufficiency of Application 

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

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

32 1.1.1.2 Timeliness of Application 

33 The timeliness of an SLRA is reviewed in accordance with 10 CFR 2.109(b). 
1.1-2 

1 1.1.2 Acceptance Criteria 

2 1.1.2.1 Docketing and Sufficiency of Application 

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

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

5 54.22, 54.23, 54.29 and 54.4. An application is sufficient if it contains the reports, analyses, and 

6 other documents required in such an application. 

7 1.1.2.2 Timeliness of Application 

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

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

10 granted) and if it is determined to be sufficient. 

11 1.1.3 Review Procedures 

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

13 renewal rule requirements for NRC review and approval prior to submitting a renewal 

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

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

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

17 However, the final determination of the sufficiency for docketing of a renewal application is 

18 made only after a formal SLRA has been submitted to the NRC. 

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

20 1.1.3.1 Docketing and Sufficiency of Application 

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

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

23 environmental information. The reviewer should use the review checklist provided in 

24 Table 1.1-1 to determine whether the application is reasonably complete and conforms to the 

25 requirements outlined in 10 CFR Part 54. 

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

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

28 application. Item II in the checklist addresses timeliness of the application. 

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

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

31 Chapters 2, 3, and 4 of the Standard Review Plan for Review of Subsequent License Renewal 

32 Applications for Nuclear Power Plants (SRP-SLR) provide information regarding the technical 

33 review. Although the purpose of the docketing and sufficiency review is not to determine the 

34 technical adequacy of the application, the reviewer should determine whether the applicant has 

35 provided reasonably complete information in the application to address the renewal rule 

36 requirements. The reviewer may request assistance from appropriate technical review 

37 branches to determine whether the application provides sufficient information to address the 

38 items in the checklist so that the NRC staff can begin their technical review. The reviewer 

39 should check the “Yes” column for a checklist item if the applicant has provided reasonably 

40 complete information in the application to address the checklist item. 
1.1-3 

1 Item VI of the checklist addresses environmental information. The environmental review NRC 

2 staff should review the supplement to the environmental report prepared by the applicant in 

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

4 Reviews for Nuclear Power Plants,” Supplement 1, “Operating License Renewal” (Ref. 1). The 

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

6 consistent with the requirements of 10 CFR Part 51. 

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

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

9 applicable, the reviewer should include a brief statement that the item is not applicable and 

10 provide the basis for the statement. 

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

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

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

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

15 application unless the applicant modifies the application to provide the missing or 

16 incomplete information. 

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

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

19 between the NRC staff and the applicant) to the applicant should clearly state that (i) the 

20 application is not sufficient and is not acceptable for docketing and (ii) the current license will 

21 expire at its expiration date. The letter also should include a description of the deficiencies 

22 found in the application and offer an opportunity for the applicant to supplement its application 

23 to provide the missing or incomplete information. The reviewer should review the 

24 supplemented application, if submitted, to determine whether it is acceptable for docketing as a 

25 sufficient application. 

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

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

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

29 30 days of receipt of a renewal application. A notice of acceptance for docketing of the 

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

31 in the Federal Register (FR). 

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

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

34 operating license for administrative convenience. 

35 1.1.3.2 Timeliness of Application 

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

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

38 supplemented application, as discussed in Subsection 1.1.3.1, is submitted at least 5 years 

39 before the expiration of the current operating license, the reviewer checks the “Yes” column for 

40 Item VII in the checklist. 

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

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

43 operating license, the letter (typically preceded by a management call between the NRC staff 
1.1-4 

1 and the applicant) to the applicant should clearly state that (i) the application is not timely, 

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

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

4 acceptable for docketing, the technical review can begin. 

5 1.1.4 Evaluation Findings 

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

7 satisfy the provisions outlined in Section 1.1.3.1 “Docketing and Sufficiency of Application” 

8 above. Depending on the results of this review, one of the following conclusions is included in 

9 the NRC staff’s letter to the applicant: 

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

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

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

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

14 review proceeds. 

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

16 the application is not acceptable for docketing as a timely and/or sufficient 

17 renewal application. 

18 1.1.5 Implementation 

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

20 complying with specified portions of NRC regulations, NRC staff members follow the methods 

21 described herein in their evaluation of conformance with NRC regulations. 

22 1.1.6 References 

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

24 Power Plants, Supplement 1, Operating License Renewal.” Washington, DC: 

25 U.S. Nuclear Regulatory Commission. October 1999.
1.1-5 

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

Acceptability for Docketing 

 Yes No 

I. General Information 

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

renewal 

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

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

 B. 10 CFR 50.4 

 a. Application is addressed to the Document Control Desk as 

specified in 10 CFR 50.4(a) 

 b. Signed original application and 13 copies are provided to 

the Document Control Desk. One copy is provided to the 

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

 c. Form of the application meets the requirements of 10 CFR 

50.4(c) 

 C. 10 CFR 50.30 

 a. Application is filed in accordance with 10 CFR 50.4 

[10 CFR 50.30(a)(1)] 

 b. Application is submitted under oath or affirmation [10 CFR 

50.30(b)] 

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

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

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

current license [10 CFR 54.17(c)] 

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

licenses [10 CFR 54.17(d)] 

 6. Information incorporated by reference in the application is contained 

in other documents previously filed with the Commission, and the 

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

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

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

54.17(f)] 

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

control of accessibility to such information is provided 

[10 CFR 54.17(g)] 

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

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

 A. Name of applicant 

 B. Address of applicant 

 C. Business description 

 D. Citizenship and ownership details 

 E. License information 

 F. Construction or alteration dates 

 G. Regulatory agencies and local publications 

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

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

account for the proposed change in the expiration date 

[10 CFR 54.19(b)] 

 
1.1-6 

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

Acceptability for Docketing (Continued)

ll. Technical Information 

 Yes No

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

consists of: 

 

 A. For those SSCs within the scope of license renewal 

[10 CFR 54.4], identification and listing of those SCs that are 

subject to an AMR in accordance with 10 CFR 54.21(a)(1)(i) 

and (ii) 

 

 a. Description of the boundary of the system or structure 

considered (if applicant initially scoped at the system or 

structure level). Within this boundary, identification of SCs 

subject to an AMR. For commodity groups, description of 

basis for the grouping 

 b. Lists of SCs subject to an AMR 

 B. Description and justification of methods used to identify SCs 

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

 C. Demonstration that the effects of aging will be adequately 

managed for each structure and component identified, so that 

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

current licensing basis for the period of extended operation 

[10 CFR 54.21(a)(3)] 

 

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

 b. Identification of applicable aging effects based on 

materials, environment, operating experience, etc. 

 c. Identification and description of AMP 

 d. Demonstration of aging management provided 

 2. An evaluation of TLAAs is provided, and consists of: 

 A. 

B. 

Listing and description of plant-specific TLAAs in accordance 

with the six criteria specified in 10 CFR 54.3 

[10 CFR 54.21(c)(1)] 

An evaluation of each identified TLAA using one of the three 

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

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

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

justifying the continuation of these exemptions for the period of 

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

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

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

 B. An evaluation of each identified exemption justifying the 

continuation of these exemptions for the period of extended 

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

 
1.1-7 

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

Acceptability for Docketing (Continued)

 Yes No 

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

following information: 

 

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

effects of aging 

 2. Summary description of the evaluation of TLAAs 

IV. Technical Specification Changes 

 Any technical specification changes necessary to manage the aging 

effects during the period of extended operation and their justifications are 

included in the application [10 CFR 54.22] 

V. Environmental Information 

 Application includes a supplement to the environmental report that is in 

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

[10 CFR 54.23] 

VI. Timeliness Provision 

 The application is sufficient and submitted at least 5 years before 

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

accepted for docketing, but the timely renewal provision in 

10 CFR 2.109(b) does not apply 

VII. Conclusions Regarding Acceptance of Application for Docketing 

 The application is reasonably complete and meets the Acceptance 

Review Checklist criteria I through V and is recommended for docketing 

2.1-1 

1 2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING 

2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

3 MANAGEMENT REVIEW AND IMPLEMENTATION RESULTS 

4 2.1 Scoping and Screening Methodology 

5 Review Responsibilities 

6 Primary—Assigned branch 

7 Secondary—None 

8 2.1.1 Areas of Review 

9 This section addresses the scoping and screening methodology for subsequent license renewal 

10 (SLR). As required by Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(2), the 

11 applicant, in its integrated plant assessment (IPA), is to describe and justify methods used to 

12 identify systems, structures, and components (SSCs) subject to an aging management review 

13 (AMR). The SSCs subject to AMR are those that perform an intended function, as described on 

14 10 CFR 54.4, and meet two criteria: 

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

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

17 and structures in this standard review plan (SRP)], and 

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

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

20 (SCs)]. 

21 The identification of the SSCs within the scope of SLR is called “scoping.” For those SSCs 

22 within the scope of SLR, the identification of “passive,” “long-lived” SCs that are subject to an 

23 AMR is called “screening.” 

24 To verify that the applicant has properly implemented its methodology, the U.S. Nuclear 

25 Regulatory Commission (NRC) staff reviews the implementation results separately, following the 

26 guidance in Sections 2.2 through 2.5. 

27 The following areas relating to the applicant’s scoping and screening methodology 

28 are reviewed. 

29 2.1.1.1 Scoping 

30 The methodology used by the applicant to implement the scoping requirements of 10 CFR 54.4, 

31 “Scope,” is reviewed. 

32 2.1.1.2 Screening 

33 The methodology used by the applicant to implement the screening requirements of 

34 10 CFR 54.21(a)(1) is reviewed. 
2.1-2 

1 2.1.2 Acceptance Criteria 

2 The acceptance criteria for the areas of review are based on the following regulations: 

3  10 CFR 54.4(a) as it relates to the identification of plant SSCs within the scope of 

4 the rule 

5  10 CFR 54.4(b) as it relates to the identification of the intended functions of plant SSCs 

6 determined to be within the scope of the rule 

7  10 CFR 54.21(a)(1) and (a)(2) as they relate to the methods utilized by the applicant to 

8 identify plant SCs subject to an AMR 

9 Specific criteria necessary to determine whether the applicant has met the relevant 

10 requirements of 10 CFR 54.4(a), 54.4(b), 54.21(a)(1), and 54.21(a)(2) are as follows. 

11 2.1.2.1 Scoping 

12 The scoping methodology used by the applicant should be consistent with the process 

13 described in Section 3.0, “Identify the SSCs within the Scope of License Renewal and Their 

14 Intended Functions,” of Nuclear Energy Institute (NEI) 95-10, “Industry Guideline for 

15 Implementing the Requirements of 10 CFR Part 54—The License Renewal Rule” (Ref. 1), or the 

16 justification provided by the applicant for any exceptions should provide a reasonable basis for 

17 the exception. 

18 2.1.2.2 Screening 

19 The screening methodology used by the applicant should be consistent with the process 

20 described in Section 4.1, “Identification of Structures and Components Subject to an Aging 

21 Management Review and Intended Functions,” of NEI 95-10 (Ref. 1), as referenced by 

22 Regulatory Guide (RG) 1.188. 

23 2.1.3 Review Procedures 

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

25 should include review of the following sources of information: 

26  The NRC’s safety evaluation report (SER) that was issued along with the operating 

27 license for the facility. 

28  The SER that was issued on the facility’s license renewal. This review is conducted for 

29 the purpose of familiarization with the principal design criteria for the facility and its 

30 current licensing basis (CLB), as defined in 10 CFR 54.3(a). 

31  Chapters 1 through 12 of the updated final safety analysis report (UFSAR) and the 

32 facility’s technical specifications for the purposes of familiarization with the facility design 

33 and the nomenclature that is applied to SSCs within the facility (including the bases for 

34 such nomenclature). During this review, the SSCs should be identified that are relied 

35 upon to remain functional during and after design basis events (DBEs), as defined in 

36 10 CFR 50.49(b)(1)(ii), for which the facility was designed, to ensure that the functions 

37 described in 10 CFR 54.4(a)(1) are successfully accomplished. This review should also 
2.1-3 

1 yield information regarding seismic Category I SSCs as defined in RG 1.29, “Seismic 

2 Design Classification” (Ref. 2). For a newer plant, this information is typically contained 

3 in Section 3.2.1, “Seismic Classification,” of the UFSAR consistent with the Standard 

4 Review Plan (NUREG–0800) (Ref. 3). 

5  Chapter 15 (or equivalent) of the UFSAR to identify the anticipated operational 

6 occurrences and postulated accidents that are explicitly evaluated in the accident 

7 analyses for the facility. During this review, the SSCs that are relied upon to remain 

8 functional during and following design basis events [as defined in 10 CFR 50.49(b)(1)] to 

9 ensure the functions described in 10 CFR 54.4(a)(1) should be identified. 

10  The set of DBEs as defined in the rule is not limited to Chapter 15 (or equivalent) of the 

11 UFSAR. Examples of DBEs that may not be described in this chapter include external 

12 events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal 

13 events, such as a high-energy line break. Information regarding DBEs as defined in 

14 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the 

15 Commission’s regulations, NRC orders, exemptions, or license conditions within the 

16 CLB. These sources should also be reviewed to identify SSCs that are relied upon to 

17 remain functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to 

18 ensure the functions described in 10 CFR 54.4(a)(1). 

19  The facility’s Probabilistic Risk Analysis (PRA) Summary Report that was prepared by 

20 the licensee in response to Generic Letter (GL) 88-20, “Individual Plant Examination for 

21 Severe Accident Vulnerabilities–10 CFR 50.54(f),” dated November 23, 1988 (Ref. 4). 

22 This review should yield additional information regarding the impact of the individual 

23 plant examination (IPE) on the CLB for the facility. While the license renewal (LR) Rule 

24 is “deterministic,” the NRC in the statements of consideration (SOC) accompanying the 

25 Rule also states that “In license renewal, probabilistic methods may be most useful, on a 

26 plant-specific basis, in helping to assess the relative importance of structures and 

27 components that are subject to an AMR by helping to draw attention to specific 

28 vulnerabilities (e.g., results of an IPE or IPEEE)” (60 FR 22468). For example, the 

29 reviewer should focus on IPE information pertaining to plant changes or modifications 

30 that are initiated by the licensee in accordance with the requirements of 10 CFR 50.59 or 

31 10 CFR 50.90. 

32  The results of the facility’s IPEEE study conducted as a follow-up to the IPE performed 

33 as a result of GL 88-20 to identify any changes or modifications made to the facility in 

34 accordance with the requirements of 10 CFR 50.59 or 10 CFR 50.90. 

35  The applicant’s docketed correspondence related to the following regulations: 

36 (a) 10 CFR 50.48, “Fire Protection” 

37 (b) 10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to 

38 Safety for Nuclear Power Plants” 

39 (c) 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against 

40 Pressurized Thermal Shock Events” or 10 CFR 50.61a, “Alternate fracture 

41 toughness requirements for protection against pressurized thermal shock 

42 events,” in accordance with the applicant’s CLB [applicable only to pressurized 

43 water reactor (PWR) plants] 
2.1-4 

1 (d) 10 CFR 50.62, “Requirements for Reduction of Risk from Anticipated Transients 

2 without Scram Events for Light-Water-Cooled Nuclear Power Plants” 

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

4 Other NRC staff members may be reviewing the applicant’s scoping and screening results 

5 separately following the guidance in Sections 2.2 through 2.5. The reviewer should keep these 

6 other NRC staff members informed of findings that may affect their review of the applicant’s 

7 scoping and screening results. The reviewer should coordinate this sharing of information 

8 through the subsequent license renewal (SLR) project manager. 

9 2.1.3.1 Scoping 

10 Once the information delineated above has been gathered, the NRC staff reviews the 

11 applicant’s methodology to determine whether its depth and breadth are sufficiently 

12 comprehensive to identify the SSCs within the scope of SLR, and the SCs requiring an AMR. 

13 Because “[t]he CLB represents the evolving set of requirements and commitments for a specific 

14 plant that are modified as necessary over the life of a plant to ensure continuation of an 

15 adequate level of safety” (60 FR 22465, May 8, 1995), the regulations, orders, license 

16 conditions, exemptions, and TSs defining functional requirements for facility SSCs that make up 

17 an applicant’s CLB should be considered as the initial input into the scoping process. DBEs are 

18 defined in 10 CFR 50.49 as conditions of normal operation, including anticipated operational 

19 occurrences and design basis accidents (DBAs). DBAs, external events, and natural 

20 phenomena for which the plant must be designed to ensure (1) the integrity of the reactor 

21 pressure boundary, (2) the capability to shut down the reactor and maintain it in safe shutdown 

22 condition, or (3) the capability to prevent or mitigate the consequences of accidents that could 

23 result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 

24 50.67(b)(2), or 100.11, as applicable. Therefore, to determine the safety-related SSCs that are 

25 within the scope of the rule under 10 CFR 54.4 (a)(1), the applicant must identify those SSCs 

26 that are relied upon to remain functional during and following these DBEs, consistent with the 

27 CLB of the facility. Most licensees have developed lists or databases that identify SSCs 

28 relied on for compliance with other regulations in a manner consistent with the CLB of their 

29 facilities. Consistent with the licensing process and regulatory criteria used to develop 

30 such lists or databases, licensees should build upon these information sources to satisfy 

31 10 CFR Part 54 requirements. 

32 With respect to technical specifications, the NRC has stated (60 FR 22467): 

33 The Commission believes that there is sufficient experience with its policy on technical 

34 specifications to apply that policy generically in revising the license renewal rule 

35 consistent with the Commission’s desire to credit existing regulatory programs. 

36 Therefore, the Commission concludes that the technical specification limiting conditions 

37 for operation scoping category is unwarranted and has deleted the requirement that 

38 identifies systems, structures, and components with operability requirements in technical 

39 specifications as being within the scope of the license renewal review. 

40 Therefore, the applicant need not consider its technical specifications and applicable limiting 

41 conditions of operation when scoping for SLR. This is not to say that the events and functions 

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

43 SSCs within the scope of SLR solely on the basis of such an event’s inclusion in the technical 

44 specifications. Rather, those SSCs governed by an applicant’s technical specifications that are 
2.1-5 

1 relied upon to remain functional during a DBE, as identified within the applicant’s UFSAR, 

2 applicable NRC regulations, license conditions, NRC orders, and exemptions, need to be 

3 included within the scope of SLR. 

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

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

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

7 considered under SLR. Generic communications, safety evaluations, and other similar 

8 documents found on the docket are not regulatory requirements, and commitments made by a 

9 licensee to address any associated safety concerns are not typically considered to be design 

10 requirements. However, any generic communication, safety evaluation, or licensee commitment 

11 that specifically identifies or describes a function associated with a SSC necessary to fulfill the 

12 requirement of a particular regulation, order, license condition, and/or exemption may need to 

13 be considered when scoping for SLR. For example, NRC Bulletin 88-11, “Pressurizer Surge 

14 Line Thermal Stratification,” states: 

15 The licensing basis according to 10 CFR 50.55a for all PWRs requires that the 

16 licensee meet the American Society of Mechanical Engineers Boiler and 

17 Pressure Vessel Code Sections III and XI and to reconcile the pipe stresses and 

18 fatigue evaluation when any significant differences are observed between 

19 measured data and the analytical results for the hypothesized conditions. Staff’s 

20 evaluation indicates that the thermal stratification phenomenon could occur in all 

21 PWR surge lines and may invalidate the analyses supporting the integrity of the 

22 surge line. The staff’s concerns include unexpected bending and thermal striping 

23 (rapid oscillation of the thermal boundary interface along the piping inside 

24 surface) as they affect the overall integrity of the surge line for its design life 

25 (e.g., the increase of fatigue). 

26 Therefore, this bulletin specifically describes conditions that may affect compliance with the 

27 requirements associated with 10 CFR 50.55a and functions specifically related to this regulation 

28 that must be considered in the scoping process for SLR. 

29 An applicant may take an approach in scoping and screening that combines similar components 

30 from various systems. For example, containment isolation valves from various systems may be 

31 identified as a single system for purposes of SLR. 

32 NRC staff from branches responsible for systems may be requested to assist in reviewing the 

33 plant design basis and intended function(s), as necessary. 

34 The reviewer should verify that the applicant’s scoping methods document the actual 

35 information sources used (for example, those identified in Table 2.1-1). 

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

37 2.1.3.1.1 Safety-Related 

38 The applicant’s methodology is reviewed to ensure that the safety-related SSCs are identified to 

39 satisfactorily accomplish any of the intended functions identified in 10 CFR 54.4(a)(1). The 

40 reviewer must ascertain how, and to what extent, the applicant incorporated the information in 

41 the CLB for the facility in its methodology. Specifically, the reviewer should review the 

42 application, as well as all other relevant sources of information outlined above, to identify the set 
2.1-6 

1 of plant-specific conditions of normal operation, DBAs, external events, and natural phenomena 

2 for which the plant must be designed to ensure the following functions: 

3  The integrity of the reactor coolant pressure boundary; 

4  The capability to shut down the reactor and maintain it in a safe shutdown condition; or 

5  The capability to prevent or mitigate the consequences of accidents that could result in 

6 potential offsite exposure comparable to the guidelines in 10 CFR 50.34(a)(1), 

7 50.67(b)(2), or 100.11, as applicable. 

8 2.1.3.1.2 Nonsafety-Related 

9 The applicant’s methodology is reviewed to ensure that nonsafety-related SSCs whose 

10 failure could prevent satisfactory accomplishment of any of the functions identified in 

11 10 CFR 54.4(a)(1) are identified as being within the scope of license renewal. 

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

13 nonsafety-related SSCs that support safety-related functions. More specifically, this scoping 

14 criterion requires an applicant to identify all nonsafety-related SSCs whose failure could prevent 

15 satisfactory accomplishment of any of the functions identified under 10 CFR 54.4(a)(1). 

16 Section III.c(iii) of the SOC (60 FR 22467) clarifies the NRC’s intent for this requirement in the 

17 following statement: 

18 The inclusion of nonsafety-related systems, structures, and components whose 

19 failure could prevent other systems, structures, and components from 

20 accomplishing a safety function is intended to provide protection against safety 

21 function failure in cases where the safety-related structure or component is not 

22 itself impaired by age-related degradation but is vulnerable to failure from the 

23 failure of another structure or component that may be so impaired. 

24 In addition, Section III.c(iii) of the SOC provides the following guidance to assist an applicant 

25 in determining the extent to which failures must be considered when applying this 

26 scoping criterion: 

27 Consideration of hypothetical failures that could result from system 

28 interdependencies that are not part of the current licensing bases and that have 

29 not been previously experienced is not required. However, for some license 

30 renewal applicants, the Commission cannot exclude the possibility that 

31 hypothetical failures that are part of the CLB may require consideration of 

32 second-, third-, or fourth-level support systems. 

33 Therefore, to satisfy the scoping criterion under 10 CFR 54.4(a)(2), the applicant must identify 

34 those nonsafety-related SSCs (including certain second-, third-, or fourth-level support systems) 

35 whose failures are considered in the CLB and could prevent the satisfactory accomplishment of 

36 a safety-related function identified under 10 CFR 54.4(a)(1). In order to identify such systems, 

37 the applicant should consider those failures identified in (1) the documentation that makes up its 

38 CLB, (2) plant-specific operating experience, and (3) industrywide operating experience that is 

39 specifically applicable to its facility. The applicant need not consider hypothetical failures that 

40 are not part of the CLB, have not been previously experienced, or are not applicable to 

41 its facility. 
2.1-7 

1 In part, 10 CFR 54.4(a)(2) requires that the applicant consider all nonsafety-related SSCs 

2 whose failure could prevent satisfactory accomplishment of any of the functions identified in 

3 10 CFR 54.4(a)(1)(i), 10 CFR 54.4(a)(1)(ii), or 10 CFR 54.4(a)(1)(iii) to be within the scope of 

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

5 staff position to NEI that provided NRC staff guidance for determining what SSCs meet the 

6 10 CFR 54.4(a)(2) criterion. The December 3, 2001 letter, “License Renewal Issue: Scoping of 

7 Seismic II/I Piping Systems,” provided specific examples of operating experience that identified 

8 pipe failure events [summarized in Information Notice (IN) 2001-09, “Main Feedwater System 

9 Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a 

10 Pressurized Water Reactor”] and the approaches the NRC considers acceptable to determine 

11 which piping systems should be included in scope based on the 10 CFR 54.4(a)(2) criterion. 

12 The March 15, 2002 letter, “License Renewal Issue: Guidance on the Identification and 

13 Treatment of Structures, Systems, and Components Which Meet 10 CFR 54.4(a)(2),” further 

14 described the NRC staff’s recommendations for the evaluation of nonpiping SSCs to determine 

15 which additional nonsafety-related SSCs are within the scope of SLR. The position states that 

16 the applicants should not consider hypothetical failures, but rather should base their evaluation 

17 on the plant’s CLB, engineering judgment and analyses, and relevant operating experience. 

18 The paper further describes operating experience as all documented plant-specific and 

19 industrywide experience that can be used to determine the plausibility of a failure. 

20 Documentation would include NRC generic communications and event reports, plant-specific 

21 condition reports, industry reports, such as significant operating experience report (SOERs), 

22 and engineering evaluations. 

23 For example, the safety classification of a pipe at certain locations, such as valves, may change 

24 throughout its length in the plant. In these instances, the applicant should identify the safety25 related portion of the pipe as being within the scope of SLR under 10 CFR 54.4(a)(1). However, 

26 the entire pipe run, including associated piping anchors, may have been analyzed as part of the 

27 CLB to establish that it could withstand DBE loads. If this is the case, a failure in the pipe run or 

28 in the associated piping anchors could render the safety-related portion of the piping unable to 

29 perform its intended function under CLB design conditions. Therefore, the reviewer must verify 

30 that the applicant’s methodology would include (1) the remaining nonsafety-related piping up to 

31 its anchors and (2) the associated piping anchors as being within the scope of SLR under 

32 10 CFR 54.4(a)(2). 

33 In order to comply, in part, with the requirements of 10 CFR 54.4(a)(2), all applicants must 

34 include in scope all nonsafety-related piping attached directly to safety-related piping (within the 

35 scope of SLR) up to a defined anchor point consistent with the plant CLB. This anchor point 

36 may be served by a true anchor [a device or structure that ensures forces and moments are 

37 restrained in three (3) orthogonal directions] or an equivalent anchor, such as a large piece of 

38 plant equipment (e.g., a heat exchanger,) determined by an evaluation of the plant-specific 

39 piping design (i.e., design documentation, such as piping stress analysis for the facility). 

40 Applicants should be able to define an equivalent anchor consistent with their CLB 

41 (e.g., described in the UFSAR or other CLB documentation), which is being credited for 

42 the 10 CFR 54.4(a)(2) evaluation, and be able to describe the SCs that are part of the 

43 nonsafety-related piping segment boundary up to and including the anchor point or equivalent 

44 anchor point within the scope of SLR. 

45 There may be isolated cases where an equivalent anchor point for a particular piping segment is 

46 not clearly described within the existing CLB information. In those instances the applicant may 

47 use a combination of restraints or supports such that the nonsafety-related piping and 
2.1-8 

1 associated SCs attached to safety-related piping is included in scope up to a boundary point 

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

3 It is important to note that the scoping criterion under 10 CFR 54.4(a)(2) specifically applies to 

4 those functions “identified in paragraphs (a)(1)(i), (ii), and (iii)” of 10 CFR 54.4 and does not 

5 apply to functions identified in 10 CFR 54.4(a)(3), as discussed below. 

6 2.1.3.1.3 “Regulated Events” 

7 The applicant’s methodology is reviewed to ensure that SSCs relied on in safety analyses or 

8 plant evaluations to perform functions that demonstrate compliance with the requirements of the 

9 fire protection, environmental qualification, pressurized thermal shock (PTS) (applicable only to 

10 PWRs), anticipated transients without scram (ATWS), and station blackout (SBO) regulations 

11 are identified. The reviewer should review the applicant’s docketed correspondence associated 

12 with compliance of the facility with these regulations. 

13 The scoping criteria in 10 CFR 54.4(a)(3) require an applicant to consider ‘All systems, 

14 structures, and components relied on in safety analyses or plant evaluations to perform a 

15 function that demonstrates compliance with the Commission's regulations. . .” In addition, 

16 Section III.c(iii) (60 FR 22467) of the SOC states that the NRC intended to limit the potential 

17 for unnecessary expansion of the review for SSCs that meet the scoping criteria under 

18 10 CFR 54.4(a)(3) and provides additional guidance that qualifies what is meant by “those 

19 SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates 

20 compliance with the Commission regulations” in the following statement: 

21 [T]he Commission intends this nonsafety-related category [§ 54.4(a)(2)] to apply to 

22 systems, structures, and components whose failure would prevent the accomplishment 

23 of an intended function of a safety-related system, structure, and component. An 

24 applicant for license renewal should rely on the plant’s CLB, actual plant-specific 

25 experience, industry-wide operating experience, as appropriate, and existing 

26 engineering evaluations to determine those nonsafety-related systems, structures, and 

27 components that are the initial focus of the license renewal review. 

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

29 plant-specific experience, industrywide experience (as appropriate), and safety analyses or 

30 plant evaluations to perform a function that demonstrates compliance with NRC regulations 

31 identified under 10 CFR 54.4(a)(3) are required to be included within the scope of the rule. For 

32 example, if a nonsafety-related diesel generator is required for safe shutdown under the fire 

33 protection plan, the diesel generator and all SSCs specifically relied upon for that generator 

34 to comply with NRC regulations shall be included within the scope of SLR under 

35 10 CFR 54.4(a)(3). Such SSCs may include, but should not be limited to, the cooling water 

36 system or systems relied upon for operability, the diesel support pedestal, and any applicable 

37 power supply cable specifically relied upon for safe shutdown in the event of a fire. 

38 In addition, the last sentence of the second paragraph in Section III.c(iii) of the SOC 

39 provides the following guidance for limiting the application of the scoping criterion under 

40 10 CFR 54.4(a)(3) as it applies to the use of hypothetical failures: Consideration of hypothetical 

41 failures that could result from system interdependencies, that are not part of the current 

42 licensing bases and that have not been previously experienced is not required. (60 FR 22467) 
2.1-9 

1 The SOC does not provide any additional guidance relating to the use of hypothetical failures 

2 or the need to consider second-, third-, or fourth-level support systems for scoping 

3 under10 CFR 54.4(a)(3). Therefore, in the absence of any guidance, an applicant need not 

4 consider hypothetical failures or second-, third-, or fourth-level support systems in determining 

5 the SSCs within the scope of the rule under 10 CFR 54.4(a)(3). For example, if a 

6 nonsafety-related diesel generator is relied upon only to remain functional to demonstrate 

7 compliance with the NRC SBO regulation, the applicant need not consider the following SSCs: 

8 (1) an alternate/backup cooling water system, (2) nonseismically-qualified building walls, or 

9 (3) an overhead segment of nonseismically-qualified piping (in a Seismic II/I configuration). This 

10 guidance is not intended to exclude any support system (whether identified by an applicant’s 

11 CLB, or as indicated from actual plant-specific experience, industrywide experience 

12 [as applicable], safety analyses, or plant evaluations) that is specifically relied upon for 

13 compliance with the applicable NRC regulation. For example, if analysis of a nonsafety-related 

14 diesel generator (relied upon to demonstrate compliance with an applicable NRC regulation) 

15 specifically relies upon a second cooling system to cool the diesel generator jacket water 

16 cooling system for the generator to be operable, then both cooling systems must be included 

17 within the scope of the rule under 10 CFR 54.4(a)(3). 

18 The applicant is required to identify the SSCs whose functions are relied upon to demonstrate 

19 compliance with the regulations identified in 10 CFR 54.4(a)(3) (that is, whose functions were 

20 credited in the analysis or evaluation). Mere mention of an SSC in the analysis or evaluation 

21 does not necessarily constitute support of an intended function as required by the regulation. 

22 For environmental qualification, the reviewer verifies that the applicant has indicated that the 

23 environmental qualification equipment is the equipment already identified by the licensee under 

24 10 CFR 50.49(b), that is, equipment relied upon in safety analyses or plant evaluations to 

25 demonstrate compliance with NRC regulations for environmental qualification (10 CFR 50.49). 

26 For SBO, the reviewer verifies that the applicant’s methodology would include those SSCs 

27 relied upon during the “coping duration” and “recovery” phase of an SBO event. In addition, 

28 because 10 CFR 50.63(c)(1)(ii) and its associated guidance in RG 1.155 include procedures to 

29 recover from an SBO that include offsite and onsite power, the offsite power system that is used 

30 to connect the plant to the offsite power source should also be included within the scope of the 

31 rule. However, the NRC staff’s review is based on the plant-specific CLB, regulatory 

32 requirements, and offsite power design configurations. 

33 2.1.3.2 Screening 

34 Once the SSCs within the scope of SLR have been identified, the next step is determining which 

35 SCs are subject to an AMR (i.e., “screening”). Table 2.1-3 contains specific NRC staff guidance 

36 on certain subjects of screening. 

37 2.1.3.2.1 “Passive” 

38 The reviewer reviews the applicant’s methodology to ensure that “passive” SCs are identified as 

39 those that perform their intended functions without moving parts or a change in configuration or 

40 properties in accordance with 10 CFR 54.21(a)(1)(i). The description of “passive” may also be 

41 interpreted to include SCs that do not display “a change in state.” 10 CFR 54.21(a)(1)(i) 

42 provides specific examples of SCs that do or do not meet the criterion. The reviewer verifies 

43 that the applicant’s screening methodology includes consideration of the intended functions of 

44 SCs consistent with the plant’s CLB, as typified in Tables 2.1-4(a) and (b), respectively . 
2.1-10 

1 The license renewal rule focuses on “passive” SCs because SCs that have passive functions 

2 generally do not have performance and condition characteristics that are as readily observable 

3 as those that perform active functions. “Passive” SCs, for the purpose of the license renewal 

4 rule, are those that perform an intended function, as described in 10 CFR 54.4, without moving 

5 parts or without a change in configuration or properties. The description of “passive” may also 

6 be interpreted to include SCs that do not display “a change of state.” 

7 Table 2.1-5 provides a list of typical SCs identifying whether they meet 

8 10 CFR 54.21(a)(1)(i). 10 CFR 54.21(a)(1)(i) explicitly excludes instrumentation, such as 

9 pressure transmitters, pressure indicators, and water level indicators, from an AMR. The 

10 applicant does not have to identify pressure-retaining boundaries of this instrumentation 

11 because 10 CFR 54.21(a)(1)(i) excludes this instrumentation without exception, unlike pumps 

12 and valves. Further, instrumentation is sensitive equipment and degradation of its pressure 

13 retaining boundary would be readily determinable by surveillance and testing. If an applicant 

14 determines that certain SCs listed in Table 2.1-5 as meeting 10 CFR 54.21(a)(1)(i) do not meet 

15 that requirement for its plant, the reviewer reviews the applicant’s basis for that determination. 

16 2.1.3.2.2 “Long-Lived” 

17 The applicant’s methodology is reviewed to ensure that “long-lived” SCs are identified as those 

18 that are not subject to periodic replacement based on a qualified life or specified time period. 

19 Passive SCs that are not replaced on the basis of a qualified life or specified time period require 

20 an AMR. 

21 Replacement programs may be based on vendor recommendations, plant experience, or any 

22 means that establishes a specific replacement frequency under a controlled program. 

23 Section f(i)(b) of the SOC provides the following guidance for identifying “long-lived” SCs: 

24 In sum, a structure or component that is not replaced either (i) on a specified 

25 interval based upon the qualified life of the structure or component or 

26 (ii) periodically in accordance with a specified time period is deemed by 

27 § 54.21(a)(1)(ii) of this rule to be “long-lived,” and therefore subject to the 

28 § 54.21(a)(3) aging management review [60 FR 22478]. 

29 A qualified life does not necessarily have to be based on calendar time. A qualified life 

30 based on run time or cycles are examples of qualified life references that are not based on 

31 calendar time. 

32 SCs that are replaced on the basis of performance or condition are not generically excluded 

33 from an AMR. Rather, performance or condition monitoring may be evaluated later in the IPA 

34 as programs to ensure functionality during the period of extended operation. On this topic, 

35 Section f(i)(b) of the SOC provides the following guidance: 

36 It is important to note, however, that the Commission has decided not to 

37 generically exclude passive structures and components that are replaced based 

38 on performance or condition from an aging management review. Absent the 

39 specific nature of the performance or condition replacement criteria and the fact 

40 that the Commission has determined that the components with “passive” 

41 functions are not as readily monitor able as components with active functions, 

42 such generic exclusion is not appropriate. However, the Commission does not 
2.1-11 

1 intend to preclude a license renewal applicant from providing site-specific 

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

3 basis of performance or condition for a passive structure or component provides 

4 reasonable assurance that the intended function of the passive structure or 

5 component will be maintained in the period of extended operation. 

6 [60 FR 22478] 

7 2.1.4 Evaluation Findings 

8 When the review of the information in the SLR application is complete, and the reviewer 

9 has determined that it is satisfactory and in accordance with the acceptance criteria in 

10 Subsection 2.1.2, a statement of the following type should be included in the NRC staff’s safety 

11 evaluation report: 

12 On the basis of its review, as discussed above, the NRC staff concludes that 

13 there is reasonable assurance that the applicant’s methodology for identifying the 

14 systems, structures, and components within the scope of subsequent license 

15 renewal and the SCs requiring an AMR is consistent with the requirements of 

16 10 CFR 54.4 and 10 CFR 54.21(a)(1). 

17 2.1.5 Implementation 

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

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

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

21 2.1.6 References 

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

23 10 CFR Part 54–The License Renewal Rule.” Revision 6. Washington, DC: 

24 Nuclear Energy Institute. 

25 2. NRC. Regulatory Guide 1.29, “Seismic Design Classification.” Revision 3. 

26 Washington, DC: U.S. Nuclear Regulatory Commission. March 2007. 

27 3. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

28 for Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

29 March 2007. 

30 4. NRC. Generic Letter (GL) 88-20, “Individual Plant Examination for Severe Accident 

31 Vulnerabilities-10 CFR 50.54(f).” Washington, DC: U.S. Nuclear Regulatory 

32 Commission. November 1988.
2.1-12 

Table 2.1-1. Sample Listing of Potential Information Sources 

Verified databases (databases that are subject to administrative controls to assure and maintain 

the integrity of the stored data or information) 

Master equipment lists (including NSSS vendor listings) 

Q-lists 

Updated Final Safety Analysis Reports 

Piping and instrument diagrams 

NRC Orders, exemptions, or license conditions for the facility 

Design-basis documents 

General arrangement or structural outline drawings 

Probabilistic risk assessment summary report 

Maintenance rule compliance documentation 

Design-basis event evaluations (including plant-specific 10 CFR 50.59 evaluation procedures) 

Emergency operating procedures 

Docketed correspondence 

System interaction commitments 

Technical specifications 

Environmental qualification program documents 

Regulatory compliance reports (including Safety Evaluation Reports) 

Severe Accident Management Guidelines 

 
2.1-13 

Table 2.1-2. Specific Staff Guidance on Scoping 

Issue Guidance

Commodity 

groups 

The applicant may also group like SCs into commodity groups. Examples of 

commodity groups are pipe supports and cable trays. The basis for grouping 

SCs can be determined by such characteristics as similar function, similar 

design, and similar materials of construction, similar aging management 

practices, or similar environments. If the applicant uses commodity groups, the 

reviewer verifies that the applicant has described the basis for the groups. 

Complex 

assemblies 

Some SCs, when combined, are considered a complex assembly (for example, 

diesel generator starting air skids or heating, ventilating, and air conditioning 

refrigerant units). For purposes of performing an AMR, it is important to clearly 

establish the boundaries of review. An applicant should establish the 

boundaries for such assemblies by identifying each structure and component 

that make up the complex assembly and determining whether or not each 

structure and component is subject to an AMR (Ref. 1). 

NEI 95-10, Revision 0, Appendix C, Example 5 (Ref. 1), illustrates how the 

evaluation boundary for a control room chiller complex assembly might be 

determined. The control room chillers were purchased as skid-mounted 

equipment. These chillers are part of the control room chilled water system. 

There are two (2) control room chillers. Each is a 100 percent capacity 

refrigeration unit. The functions of the control room chillers are to provide a 

reliable source of chilled water at a maximum temperature of 7 °

C [44 °F], to 

provide a pressure boundary for the control room chilled water system, to 

provide a pressure boundary for the service water system, and to provide a 

pressure boundary for the refrigerant. All of these functions are considered 

intended functions. Typically, control room chillers are considered as one 

functional unit; however, for purposes of evaluating the effects of aging, it is 

necessary to consider the individual components. Therefore, the boundary of 

each control room chiller is established as follows: 

1. At the inlet and outlet flanges of the service water system connections on 

the control room chiller condenser. Connected piping is part of the service 

water system. 

2. At the inlet and outlet flanges of the control room chilled water system 

piping connections on the control room chiller evaporator. Connected 

piping is part of the control room chilled water system. 

3. For electrical power supplies, the boundary is the output terminals on the 

circuit breakers supplying power to the skid. This includes the cables from 

the circuit breaker to the skid and applies for 480 VAC and 120 VAC. 

4. The interface for instrument air supplies is at the instrument air tubing 

connection to the pressure control regulators, temperature controllers and 

transmitters, and solenoid valves located on the skid. The tubing from the 

instrument air header to the device on the skid is part of the instrument air 

system. 

5. The interface with the annunciator system is at the external connection of 

the contacts of the device on the skid (limit switch, pressure switch, level 
2.1-14 

Table 2.1-2. Specific Staff Guidance on Scoping 

Issue Guidance

switch, etc.) that indicates the alarm condition. The cables are part of the 

annunciator system. 

Based on the boundary established, the following components would be subject 

to an AMR: condenser, evaporator, economizer, chiller refrigerant piping, 

refrigerant expansion orifice, foundations and bolting, electrical cabinets, 

cables, conduit, trays and supports, valves 

Hypothetical 

failures 

For 10 CFR 54.4(a)(2), an applicant should consider those failures identified in 

(1) the documentation that makes up its CLB, (2) plant-specific operating 

experience, and (3) industrywide operating experience that is specifically 

applicable to its facility. The applicant need not consider hypothetical failures 

that are not part of CLB and that have not been previously experienced. 

For example, an applicant should consider including (1) the portion of a fire 

protection system identified in the UFSAR that supplies water to the refueling 

floor that is relied upon in a DBA analysis as an alternate source of cooling 

water that can be used to mitigate the consequences from the loss of spent fuel 

pool cooling, (2) a nonsafety-related, non-seismically-qualified building whose 

intended function as described in the plant’s CLB is to protect a tank that is 

relied upon as an alternate source of cooling water needed to mitigate the 

consequences of a DBE, and (3) a segment of nonsafety-related piping 

identified as a Seismic II/I component in the applicant’s CLB. 

Cascading For 10 CFR 54.4(a)(3), an applicant need not consider hypothetical failures or 

second-, third, or fourth-level support systems. For example, if a nonsafetyrelated diesel generator is only relied upon to remain functional to demonstrate 

compliance with the NRC’s SBO regulations, an applicant may not need to 

consider (1) an alternate/backup cooling water system, (2) the diesel generator 

non-seismically-qualified building walls, or (3) an overhead segment of nonseismically-qualified piping (in a Seismic II/I configuration). An applicant may 

not exclude any support system (identified by its CLB, actual plant-specific 

experience, industrywide experience, as applicable, or existing engineering 

evaluations) that is specifically relied upon for compliance with, or operation 

within, applicable NRC regulation. For example, if the analysis of a nonsafetyrelated diesel generator (relied upon to demonstrate compliance with an 

applicable NRC regulation) specifically relies upon a second cooling system to 

cool the diesel generator jacket water cooling system for the diesel to be 

operable, then both cooling systems must be included within the scope of 

the rule. 
2.1-15 

Table 2.1-3. Specific Staff Guidance on Screening 

Issue Guidance 

Consumables Consumables may be divided into the following four categories for the purpose 

of license renewal: (a) packing, gaskets, component seals, and O-rings; 

(b) structural sealants; (c) oil, grease, and component filters; and (d) system 

filters, fire extinguishers, fire hoses, and air packs. The consumables in both 

categories (a) and (b) are considered as subcomponents and are not explicitly 

called out in the scoping and screening procedures. Rather, they are implicitly 

included at the component level (e.g., if a valve is identified as being in scope, a 

seal in that valve would also be in scope as a subcomponent of that valve). For 

category (a), the applicant would generally be able to exclude these 

subcomponents using a clear basis. For category (b), these subcomponents 

may perform functions without moving parts or a change in configuration, and 

they are not typically replaced. The applicant’s structural AMP should address 

these items with respect to an AMR program on a plant-specific basis. The 

consumables in category (c) are usually short-lived and periodically replaced, 

and can normally be excluded from an AMR on that basis. Likewise, the 

consumables that fall within category (d) are typically replaced based on 

performance or condition monitoring that identifies whether these components 

are at the end of their qualified lives and may be excluded, on a plant-specific 

basis, from AMR under 10 CFR 54.21(a)(1)(ii). The applicant should identify 

the standards that are relied on for the replacement as part of the methodology 

description (for example, NFPA standards for fire protection equipment). 

Heat 

exchanger 

intended 

functions 

Both the pressure boundary and heat transfer functions for heat exchangers 

should be considered because heat transfer may be a primary safety function 

of these components. There may be a unique aging effect associated with 

different materials in the heat exchanger parts that are associated with the heat 

transfer function and not the pressure boundary function. Normally the 

programs that effectively manage aging effects of the pressure boundary 

function can, in conjunction with the procedures for monitoring heat exchanger 

performance, effectively manage aging effects applicable to the heat 

transfer function. 

Multiple 

functions 

SCs may have multiple functions. The intended functions as delineated in 

10 CFR 54.4(b) are to be reviewed for SLR. For example, a flow orifice that is 

credited in a plant’s accident analysis to limit flow would have two intended 

functions. One intended function is pressure boundary. The other intended 

function is to limit flow. The reviewer verifies that the applicant has considered 

multiple functions in identifying structure- and component-intended functions. 
2.1-16 

Table 2.1-4(a). Typical “Passive” Structure-Intended Functions 

Structures 

Intended Function Description 

Direct Flow Provide spray shield or curbs for directing flow (e.g., safety 

injection flow to containment sump) 

Expansion/Separation Provide for thermal expansion and/or seismic separation 

Fire Barrier Provide rated fire barrier to confine or retard a fire from 

spreading to or from adjacent areas of the plant 

Flood Barrier Provide flood protection barrier (internal and external 

flooding event) 

Gaseous Release Path Provide path for release of filtered and unfiltered 

gaseous discharge 

Heat Sink Provide heat sink during station blackout or designbasis accidents 

HELB Shielding Provide shielding against HELB 

Missile Barrier Provide missile barrier (internally or externally generated) 

Pipe Whip Restraint Provide pipe whip restraint 

Pressure Relief Provide over-pressure protection 

Shelter, Protection Provide shelter/protection to safety-related components 

Shielding Provide shielding against radiation 

Shutdown Cooling Water Provide source of cooling water for plant shutdown 

Structural Pressure Barrier Provide pressure boundary or essentially leak-tight barrier to 

protect public health and safety in the event of any postulated 

design-basis events. 
2.1-17 

Table 2.1-4(b). Typical “Passive” Component-Intended Functions 

Components 

Intended Function Description 

Absorb Neutrons Absorb neutrons 

Electrical Continuity Provide electrical connections to specified sections of an 

electrical circuit to deliver voltage, current, or signals 

Insulate (electrical) Insulate and support an electrical conductor 

Filter Provide filtration 

Heat Transfer Provide heat transfer 

Leakage Boundary (Spatial) Nonsafety-related component that maintains mechanical 

and structural integrity to prevent spatial interactions that 

could cause failure of safety-related SSCs 

Pressure Boundary Provide pressure-retaining boundary so that sufficient flow 

at adequate pressure is delivered, or provide fission 

product barrier for containment pressure boundary, or 

provide containment isolation for fission product retention 

Spray Convert fluid into spray 

Structural Integrity (Attached) Nonsafety-related component that maintains mechanical 

and structural integrity to provide structural support to 

attached safety-related piping and components 

Structural Support Provide structural and/or functional support to 

safety-related and/or nonsafety-related components 

Throttle Provide flow restriction 
2.1-18 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

1 Structures Category I Structures Yes 

2 Structures Primary Containment 

Structure 

Yes 

3 Structures Intake Structures Yes 

4 Structures Intake Canal Yes 

5 Structures Other Non-Category I 

Structures within the 

Scope of SLR 

Yes 

6 Structures Equipment Supports 

and Foundations 

Yes 

7 Structures Structural Bellows Yes 

8 Structures Controlled Leakage 

Doors 

Yes 

9 Structures Penetration Seals Yes 

10 Structures Compressible Joints 

and Seals 

Yes 

11 Structures Fuel Pool and Sump 

Liners 

Yes 

12 Structures Concrete Curbs Yes 

13 Structures Offgas Stack and Flue Yes 

14 Structures Fire Barriers Yes 

15 Structures Pipe Whip Restraints 

and Jet Impingement 

Shields 

Yes 

16 Structures Electrical and 

Instrumentation and 

Control Penetration 

Assemblies 

Yes 

17 Structures Instrumentation Racks, 

Frames, Panels, and 

Enclosures 

Yes 

18 Structures Electrical Panels, 

Racks, Cabinets, and 

Other Enclosures 

Yes 

19 Structures Cable Trays and 

Supports 

Yes 

20 Structures Conduit Yes 

21 Structures TubeTrack® Yes 

22 Structures Reactor Vessel 

Internals 

Yes 

23 Structures ASME Class 1 

Hangers and Supports

Yes 
2.1-19 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

24 Structures Non-ASME Class 1 

Hangers and Supports

Yes 

25 Structures Snubbers No 

26 Reactor Coolant 

Pressure Boundary 

Components 

(Note: the components 

of the RCPB are 

defined by each plant's 

CLB and site-specific 

documentation) 

ASME Class 1 Piping Yes 

27 Reactor Coolant 

Pressure Boundary 

Components 

Reactor Vessel Yes 

28 Reactor Coolant 

Pressure Boundary 

Components 

Reactor Coolant 

Pumps 

Yes (Casing) 

29 Reactor Coolant 

Pressure Boundary 

Components 

Control Rod Drives No 

30 Reactor Coolant 

Pressure Boundary 

Components 

Control Rod Drive 

Housing 

Yes 

31 Reactor Coolant 

Pressure Boundary 

Components 

Steam Generators Yes 

32 Reactor Coolant 

Pressure Boundary 

Components 

Pressurizers Yes 

33 Non-Class I Piping 

Components 

Underground Piping Yes 

34 Non-Class I Piping 

Components 

Piping in Low 

Temperature 

Demineralized Water 

Service 

Yes 

35 Non-Class I Piping 

Components 

Piping in High 

Temperature Single 

Phase Service 

Yes 

36 Non-Class I Piping 

Components 

Piping in Multiple 

Phase Service 

Yes 

37 Non-Class I Piping 

Components 

Service Water Piping Yes 
2.1-20 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

38 Non-Class I Piping 

Components 

Low Temperature Gas 

Transport Piping 

Yes 

39 Non-Class I Piping 

Components 

Stainless Steel Tubing Yes 

40 Non-Class I Piping 

Components 

Instrument Tubing Yes 

41 Non-Class I Piping 

Components 

Expansion Joints Yes 

42 Non-Class I Piping 

Components 

Ductwork Yes 

43 Non-Class I Piping 

Components 

Sprinkler Heads Yes 

44 Non-Class I Piping 

Components 

Miscellaneous 

Appurtenances 

(Includes fittings, 

couplings, reducers, 

elbows, thermowells, 

flanges, fasteners, 

welded attachments, 

etc.) 

Yes 

45 Pumps ECCS Pumps Yes (Casing) 

46 Pumps Service Water and Fire 

Pumps 

Yes (Casing) 

47 Pumps Lube Oil and Closed 

Cooling Water Pumps 

Yes (Casing) 

48 Pumps Condensate Pumps Yes (Casing) 

49 Pumps Borated Water Pumps Yes (Casing) 

50 Pumps Emergency Service 

Water Pumps 

Yes (Casing) 

51 Pumps Submersible Pumps Yes (Casing) 

52 Turbines Turbine Pump Drives 

(excluding pumps) 

Yes (Casing) 

53 Turbines Gas Turbines Yes (Casing) 

54 Turbines Controls (Actuator and 

Overspeed Trip) 

No 

55 Engines Fire Pump Diesel 

Engines 

No 

56 Emergency Diesel 

Generators 

Emergency Diesel 

Generators 

No 

57 Heat Exchangers Condensers Yes 
2.1-21 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

58 Heat Exchangers Heating, ventilation, 

and air conditioning 

(HVAC) Coolers 

(including housings) 

Yes 

59 Heat Exchangers Primary Water System 

Heat Exchangers 

Yes 

60 Heat Exchangers Treated Water System 

Heat Exchangers 

Yes 

61 Heat Exchangers Closed Cooling Water 

System Heat 

Exchangers 

Yes 

62 Heat Exchangers Lubricating Oil System 

Heat Exchangers 

Yes 

63 Heat Exchangers Raw Water System 

Heat Exchangers 

Yes 

64 Heat Exchangers Containment 

Atmospheric System 

Heat Exchangers 

Yes 

65 Miscellaneous Process 

Components 

Gland Seal Blower No 

66 Miscellaneous Process 

Components 

Recombiners The applicant shall 

identify the intended 

function and apply the 

IPA process to 

determine if the 

grouping is active or 

passive. 

67 Miscellaneous Process 

Components 

Flexible Connectors Yes 

68 Miscellaneous Process 

Components 

Strainers Yes 

69 Miscellaneous Process 

Components 

Rupture Disks Yes 

70 Miscellaneous Process 

Components 

Steam Traps Yes 

71 Miscellaneous Process 

Components 

Restricting Orifices Yes 

72 Miscellaneous Process 

Components 

Air Compressor No 

73 Electrical and 

instrumentation and 

control 

Alarm Unit (e.g., fire 

detection devices) 

No 
2.1-22 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

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

analyzers, conductivity 

analyzers) 

No 

75 Electrical and I&C Annunciators (e.g., 

lights, buzzers, 

alarms) 

No 

76 Electrical and I&C Batteries No 

77 Electrical and I&C Cables and 

Connections, Bus, 

electrical portions of 

Electrical and I&C 

Penetration 

Assemblies, includes 

fuse holders outside of 

cabinets of active 

electrical SCs (e.g., 

electrical penetration 

assembly cables and 

connections, 

connectors, electrical 

splices, fuse holders, 

terminal blocks, power 

cables, control cables, 

instrument cables, 

insulated cables, 

communication cables, 

uninsulated ground 

conductors, 

transmission 

conductors, isolatedphase bus, 

non-segregated-phase 

bus, segregated-phase 

bus, switchyard bus) 

Yes 
2.1-23 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

78 Electrical and I&C Chargers, Converters, 

Inverters 

(e.g., convertersvoltage/current, 

convertersvoltage/pneumatic, 

battery 

chargers/inverters, 

motor-generator sets) 

No 

79 Electrical and I&C Circuit Breakers (e.g., 

air circuit breakers, 

molded case circuit 

breakers, oil-filled 

circuit breakers) 

No 

80 Electrical and I&C Communication 

Equipment (e.g., 

telephones, video or 

audio recording or 

playback equipment, 

intercoms, computer 

terminals, electronic 

messaging, radios, 

transmission line traps, 

and other power-line 

carrier equipment) 

No 

81 Electrical and I&C Electric Heaters No 

Yes for a Pressure 

Boundary if applicable

82 Electrical and I&C Heat Tracing No 

83 Electrical and I&C Electrical Controls and 

Panel Internal 

Component 

Assemblies (may 

include internal 

devices such as, but 

not limited to, 

switches, breakers, 

indicating lights, etc.) 

(e.g., main control 

board, HVAC control 

board) 

No 
2.1-24 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

84 Electrical and I&C Elements, RTDs, 

Sensors, 

Thermocouples, 

Transducers (e.g., 

conductivity elements, 

flow elements, 

temperature sensors, 

radiation sensors, watt 

transducers, 

thermocouples, RTDs, 

vibration probes, amp 

transducers, frequency 

transducers, power 

factor transducers, 

speed transducers, 

var. transducers, 

vibration transducers, 

voltage transducers) 

No 

Yes for a pressure 

boundary if applicable

85 Electrical and I&C Fuses No 

86 Electrical and I&C Generators, Motors 

(e.g., emergency 

diesel generators, 

ECCS and emergency 

service water pump 

motors, small motors, 

motor-generator sets, 

steam turbine 

generators, 

combustion turbine 

generators, fan 

motors, pump motors, 

valve motors, air 

compressor motors) 

No 

87 Electrical and I&C High-Voltage 

Insulators 

(e.g., porcelain 

switchyard insulators, 

transmission line 

insulators) 

Yes 
2.1-25 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

88 Electrical and I&C Surge Arresters (e.g., 

switchyard surge 

arresters, lightning 

arresters, surge 

suppressers, surge 

capacitors, protective 

capacitors) 

No 

89 Electrical and I&C Indicators (e.g., 

differential pressure 

indicators, pressure 

indicators, flow 

indicators, level 

indicators, speed 

indicators, temperature 

indicators, analog 

indicators, digital 

indicators, LED bar 

graph indicators, 

LCD indicators) 

No 

90 Electrical and I&C Isolators 

(e.g., transformer 

isolators, optical 

isolators, isolation 

relays, isolating 

transfer diodes) 

No 

91 Electrical and I&C Light Bulbs 

(e.g., indicating lights, 

emergency lighting, 

incandescent light 

bulbs, fluorescent 

light bulbs) 

No 
2.1-26 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

92 Electrical and I&C Loop Controllers (e.g., 

differential pressure 

indicating controllers, 

flow indicating 

controllers, 

temperature 

controllers, controllers, 

speed controllers, 

programmable logic 

controller, single loop 

digital controller, 

process controllers, 

manual loader, 

selector station, 

hand/auto station, 

auto/manual station) 

No 

93 Electrical and I&C Meters 

(e.g., ammeters, volt 

meters, frequency 

meters, var meters, 

watt meters, power 

factor meters, 

watt-hour meters) 

No 

94 Electrical and I&C Power Supplies No 

95 Electrical and I&C Radiation Monitors 

(e.g., area radiation 

monitors, process 

radiation monitors) 

No 

96 Electrical and I&C Recorders (e.g., chart 

recorders, digital 

recorders, events 

recorders) 

No 

97 Electrical and I&C Regulators 

(e.g., voltage 

regulators) 

No 

98 Electrical and I&C Relays (e.g., protective 

relays, control/logic 

relays, auxiliary relays)

No 

99 Electrical and I&C Signal Conditioners No 

100 Electrical and I&C Solenoid Operators No 
2.1-27 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

101 Electrical and I&C Solid-State Devices 

(e.g., transistors, 

circuit boards, 

computers) 

No 

102 Electrical and I&C Switches 

(e.g., differential 

pressure indicating 

switches, differential 

pressure switches, 

pressure indicator 

switches, pressure 

switches, flow 

switches, conductivity 

switches, levelindicating switches, 

temperature-indicating 

switches, temperature 

switches, moisture 

switches, position 

switches, vibration 

switches, level 

switches, control 

switches, automatic 

transfer switches, 

manual transfer 

switches, manual 

disconnect switches, 

current switches, limit 

switches, knife 

switches) 

No 
2.1-28 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

103 Electrical and I&C Switchgear, Load 

Centers, Motor Control 

Centers, Distribution 

Panel Internal 

Component 

Assemblies 

(may include internal 

devices such as, but 

not limited to, 

switches, breakers, 

indicating lights, etc.) 

(e.g., 4.16 kV 

switchgear, 480V load 

centers, 480V motor 

control centers, 250 

VDC motor control 

centers, 6.9 kV 

switchgear units, 

240/125V power 

distribution panels) 

No 

104 Electrical and I&C Transformers 

(e.g., instrument 

transformers, load 

center transformers, 

small distribution 

transformers, large 

power transformers, 

isolation transformers, 

coupling capacitor 

voltage transformers) 

No 

105 Electrical and I&C Transmitters 

(e.g., differential 

pressure transmitters, 

pressure transmitters, 

flow transmitters, level 

transmitters, radiation 

transmitters, static 

pressure transmitters) 

No 

106 Valves Hydraulic-Operated 

Valves 

Yes (Bodies) 

107 Valves Explosive Valves Yes (Bodies) 

108 Valves Manual Valves Yes (Bodies) 
2.1-29 

Table 2.1-5. Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment 

Item Category 

Structure, 

Component, or 

Commodity 

Grouping 

Structure, 

Component, or 

Commodity 

Group Meets 

10 CFR 54.21(a)(1)(i) 

(Yes/No) 

109 Valves Small Valves Yes (Bodies) 

110 Valves Motor-Operated 

Valves 

Yes (Bodies) 

111 Valves Air-Operated Valves Yes (Bodies) 

112 Valves Main Steam Isolation 

Valves 

Yes (Bodies) 

113 Valves Small Relief Valves Yes (Bodies) 

114 Valves Check Valves Yes (Bodies) 

115 Valves Safety Relief Valves Yes (Bodies) 

116 Valves Dampers, louvers, and 

gravity dampers 

Yes (Housings) 

117 Tanks Air Accumulators Yes 

118 Tanks Discharge 

Accumulators 

(Dampers) 

Yes 

119 Tanks Boron Acid Storage 

Tanks 

Yes 

120 Tanks Above Ground Oil 

Tanks 

Yes 

121 Tanks Underground Oil 

Tanks 

Yes 

122 Tanks Demineralized Water 

Tanks 

Yes 

123 Tanks Neutron Shield Tank Yes 

124 Fans Ventilation Fans 

(includes intake fans, 

exhaust fans, and 

purge fans) 

Yes (Housings) 

125 Fans Other Fans Yes (Housings) 

126 Miscellaneous Emergency Lighting No 

127 Miscellaneous Hose Stations Yes 

2.2-1 

1 2.2 Plant-Level Scoping Results 

2 Review Responsibilities 

3 Primary—Assigned branch(s) 

4 Secondary—None 

5 2.2.1 Areas of Review 

6 This section addresses the plant-level scoping results for subsequent license renewal (SLR). 

7 Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires the applicant to 

8 identify and list structures and components (SCs) subject to an aging management review 

9 (AMR). These are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 

10 10 CFR 54.21(a)(2) requires the applicant to describe and justify the methods used to identify 

11 these SCs. The U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s 

12 methodology separately, following the guidance in Section 2.1. 

13 The applicant should provide a list of all the plant systems and structures, identifying those that 

14 are within the scope of SLR. If the list exists elsewhere, such as in the updated final safety 

15 analysis report (UFSAR), it is acceptable to merely identify the reference. The license renewal 

16 rule does not require the identification of all plant systems and structures within the scope of 

17 SLR. However, providing such a list may make the review more efficient. 

18 On the basis of the design basis events (DBEs) considered in the plant’s current licensing basis 

19 (CLB) and other CLB information relating to nonsafety-related systems and structures and 

20 certain regulated events, the applicant would identify those plant-level systems and structures 

21 within the scope of SLR, as defined in 10 CFR 54.4(a). This is “scoping” of the plant- level 

22 systems and structures for SLR. To verify that the applicant has properly implemented its 

23 methodology, the NRC staff focuses its review on the implementation results to confirm that 

24 there is no omission of plant-level systems and structures within the scope of SLR. 

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

26 [boiling water reactor (BWR)], emergency core cooling, open and closed cycle cooling water, 

27 compressed air, chemical and volume control (PWR), standby liquid control (BWR), main 

28 steam, feedwater, condensate, steam generator blowdown (PWR), and auxiliary feedwater 

29 (AFW) systems (PWR). 

30 Examples of plant structures are the primary containment, secondary containment (BWR), 

31 control room, auxiliary building, fuel storage building, radwaste building, and ultimate heat sink 

32 cooling tower. 

33 Examples of components are the reactor vessel, reactor vessel internals, steam generator 

34 (PWR), and light and heavy load-handling cranes. Some applicants may have categorized such 

35 components as plant “systems” for their convenience. 

36 After plant-level scoping, the applicant should identify the portions of the system or structure 

37 that perform an intended function, as defined in 10 CFR 54.4(b). Then the applicant should 

38 identify those SCs that are “passive” and “long-lived,” in accordance with 10 CFR 54.21(a)(1)(i) 

39 and (ii). These “passive,” “long-lived” SCs are those that are subject to an AMR. The NRC staff 

40 reviews these results separately following the guidance in Sections 2.3 through 2.5. 
2.2-2 

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

2 within the scope of SLR, provided that this set includes the systems and structures that the NRC 

3 has determined are within the scope of SLR. Therefore, the reviewer need not review all 

4 systems and structures that the applicant has identified to be within the scope of SLR because 

5 the applicant has the option to include more systems and components than those defined to be 

6 within the scope of SLR by 10 CFR 54.4. 

7 The following areas relating to the methodology implementation results for the plant-level 

8 systems and structures are reviewed. 

9 2.2.1.1 Systems and Structures Within the Scope of Subsequent License Renewal 

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

11 within the scope of SLR. 

12 2.2.2 Acceptance Criteria 

13 The acceptance criteria for the area of review define methods for determining whether the 

14 applicant has identified the systems and structures within the scope of SLR in accordance with 

15 NRC regulations in 10 CFR 54.4. For the applicant’s implementation of its methodology to be 

16 acceptable, the NRC staff should have reasonable assurance that there has been no omission 

17 of plant-level systems and structures within the scope of SLR. 

18 2.2.2.1 Systems and Structures Within the Scope of Subsequent License Renewal 

19 Systems and structures are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are 

20  Safety-related systems and structures that are relied upon to remain functional during 

21 and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the following functions: 

22 – The integrity of the reactor coolant pressure boundary, 

23 – The capability to shut down the reactor and maintain it in a safe shutdown 

24 condition, or 

25 – The capability to prevent or mitigate the consequences of accidents that could 

26 result in potential offsite exposure comparable to the guidelines in 

27 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.11, as applicable. 

28  All nonsafety-related systems and structures whose failure could prevent satisfactory 

29 accomplishment of any of the functions identified in 10 CFR 54.4(a)(1) above. 

30  All systems and structures relied on in safety analyses or plant evaluations to perform a 

31 function that demonstrates compliance with NRC regulations for fire protection 

32 (10 CFR 50.48), environmental qualification (10 CFR 50.49), PTS (10 CFR 50.61), 

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

34 2.2.3 Review Procedures 

35 The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

36 additional information from the applicant regarding why a certain system or structure was not 
2.2-3 

1 identified by the applicant as being within the scope of SLR for the applicant’s plant, the 

2 reviewer should provide a focused question, clearly explaining what information is needed, 

3 explaining why it is needed, and how it will allow the NRC staff to make its safety finding. In 

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

5 separately following the guidance in Section 2.1. The reviewer should keep these other NRC 

6 staff members informed of findings that may affect their review of the applicant’s methodology. 

7 The reviewer should coordinate this sharing of information through the SLR project manager. 

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

9 2.2.3.1 Systems and Structures Within the Scope of Subsequent License Renewal 

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

11 and structures within the scope of SLR by reviewing selected systems and structures that the 

12 applicant did not identify as being within the scope of SLR to verify that they do not have any 

13 intended functions. 

14 The reviewer should use the plant UFSAR, orders, applicable regulations, exemptions, and 

15 license conditions to determine the design basis for the SSCs (if components are identified as 

16 “systems” by the applicant). The design basis determines the intended function(s) of an SSC. 

17 Such functions determine whether the SSC is within the scope of SLR under 10 CFR 54.4. 

18 This section addresses scoping at a system or structure level. Thus, if any portion of a system 

19 or structure performs an intended function as defined in 10 CFR 54.4(b), the system or structure 

20 is within the scope of SLR. The review of individual portions of systems and structures that are 

21 within the scope of SLR are addressed separately in Sections 2.3 through 2.5. 

22 The applicant should submit a list of all plant-level systems and structures, identifying those that 

23 are within the scope of SLR (54.4) and subject to AMR [54.21(a)(1)]. The reviewer should 

24 sample selected systems and structures that the applicant did not identify as within the scope of 

25 SLR to determine if they perform any intended functions. The following are examples: 

26  The applicant does not identify the radiation monitoring system as being within the scope 

27 of SLR. The reviewer may review the UFSAR to verify that this particular system does 

28 not perform any intended functions at the applicant’s plant. 

29  The applicant does not identify the polar crane as being within the scope of SLR. The 

30 reviewer may review the UFSAR to verify that this particular structure is not “Seismic II 

31 over I,” denoting a structure that is not seismic Category I interacting with a Seismic 

32 Category I structure as described in Position C.2 of Regulatory Guide (RG) 1.29, 

33 “Seismic Design Classification” (Ref. 1). 

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

35 SLR. The reviewer may review the plant’s commitments to the fire protection regulation 

36 (10 CFR 50.48) to verify that this particular structure does not perform any intended 

37 functions at the plant. 

38  The applicant uses the “spaces” approach for scoping electrical equipment and elects to 

39 include all electrical equipment onsite to be within the scope of SLR except for the 

40 525 kV switchyard and the 230 kV transmission lines. The reviewer may review the 

41 UFSAR and commitments to the SBO regulation (10 CFR 50.63) to verify that the 
2.2-4 

1 525 kV switchyard and the 230 kV transmission lines do not perform any intended 

2 functions at the applicant’s plant. 

3 The applicant may choose to group similar components and structures together in commodity 

4 groups for separate analyses. If only a portion of a system or structure has an intended function 

5 and is addressed separately in a specific commodity group, it is acceptable for an applicant to 

6 identify that system or structure as not being within the scope of SLR. However, for 

7 completeness, the applicant should include some reference indicating that the portion of the 

8 system or structure with an intended function that is evaluated with the commodity group. 

9 Section 2.1 contains additional guidance on the following: 

10  Commodity groups 

11  Complex assemblies 

12  Hypothetical failure 

13  Cascading 

14 If the reviewer has reviewed systems and structures in sufficient detail and does not identify any 

15 omissions of systems and structures from those within the scope of SLR, the NRC staff would 

16 have reasonable assurance that the applicant has identified the systems and structures within 

17 the scope of SLR. 

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

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

20 systems and structures within the scope of SLR. 

21 2.2.4 Evaluation Findings 

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

23 provisions of the SRP-SLR, then the NRC staff’s evaluation supports conclusions of the 

24 following type, to be included in the SER: 

25 On the basis of its review, as discussed above, the NRC staff concludes that 

26 there is reasonable assurance that the applicant has appropriately identified the 

27 systems and structures within the scope of SLR in accordance with 10 CFR 54.4. 

28 2.2.5 Implementation 

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

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

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

32 2.2.6 References 

33 1. NRC. Regulatory Guide 1.29, “Seismic Design Classifications.” Revision 3. 

34 Washington, DC: U.S. Nuclear Regulatory Commission. March 2007. 
2.2-5 

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

Example Disposition 

Recirculation cooling water 

system 

One function of the recirculation cooling water system is to 

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

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

fuel pool cooling system at the subject facility is not safetyrelated, and, following a seismic event, the safety-related 

spent fuel pool structure and spent fuel pool makeup water 

supplies ensure the adequate removal of decay heat to 

prevent potential offsite exposures comparable to those 

described in 10 CFR Part 100. Therefore, the recirculation 

cooling water system is not within the scope of SLR based 

on the spent fuel decay heat removal function. 

SBO diesel generator building The plant’s UFSAR indicates that certain structural 

components of the SBO diesel generator building for the 

plant are designed to preclude seismic failure and 

subsequent impact of the structure on the adjacent 

safety-related emergency diesel generator building. In 

addition, the UFSAR indicates that certain equipment 

attached to the roof of the building has been anchored to 

resist tornado wind loads. Thus, the SBO diesel generator 

building is within the scope of SLR. 

2.3-1 

1 2.3 Scoping And Screening Results: Mechanical Systems 

2 Review Responsibilities 

3 Primary—Assigned branch(s) 

4 Secondary—None 

5 2.3.1 Areas of Review 

6 This section addresses the mechanical systems scoping and screening results for subsequent 

7 license renewal (SLR). Typical mechanical systems consist of the following: 

8  Reactor coolant system (such as reactor vessel and internals, components forming part 

9 of coolant pressure boundary, coolant piping system and connected lines, and 

10 steam generators). 

11  Engineered safety features (such as containment spray and isolation systems, standby 

12 gas treatment system, emergency core cooling system, and fan cooler system). 

13  Auxiliary systems (such as new and spent fuel storage, spent fuel cooling and cleanup 

14 systems, suppression pool cleanup system, load handling system, open and closed 

15 cycle cooling water systems, ultimate heat sink, compressed air system, chemical and 

16 volume control system, standby liquid control system, coolant storage/refueling water 

17 systems, ventilation systems, diesel generator system, and fire protection system). 

18  Steam and power conversion system (such as turbines, main and extraction steam, 

19 feedwater, condensate, steam generator blowdown, and auxiliary feedwater). 

20 Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to 

21 identify and list structures and components (SCs) subject to an aging management review 

22 (AMR). These are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 

23 10 CFR 54.21(a)(2) requires an applicant to describe and justify the methods used to identify 

24 these SCs. The U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s 

25 methodology separately following the guidance in Section 2.1. To verify that the applicant has 

26 properly implemented its methodology, the NRC staff focuses its review on the implementation 

27 results. Such a focus allows the NRC staff to confirm that there is no omission of mechanical 

28 system components that are subject to an AMR by the applicant. If the review identifies no 

29 omission, the NRC staff has the basis to find that there is reasonable assurance that the 

30 applicant has identified the mechanical system components that are subject to an AMR. 

31 An applicant should list all plant-level systems and structures. On the basis of the design basis 

32 events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information

33 relating to nonsafety-related systems and structures and certain regulated events, the applicant 

34 should identify those plant-level systems and structures within the scope of SLR, as defined in 

35 10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. The NRC 

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

37 Section 2.2. 

38 For a mechanical system that is within the scope of SLR, the applicant should identify the 

39 portions of the system that perform an intended function, as defined in 10 CFR 54.4(b). The 
2.3-2 

1 applicant may identify these particular portions of the system in marked-up piping and 

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

3 a system to identify those that are within the scope of SLR for a system. 

4 For those identified mechanical components that are within the scope of SLR, the applicant 

5 must identify those that are “passive” and “long-lived,” as required by 10 CFR 54.21(a)(1)(i) and 

6 (ii). These “passive,” “long-lived” mechanical components are those that are subject to an AMR. 

7 This is “screening” of mechanical components in a system to identify those that are “passive” 

8 and “long-lived.” 

9 The applicant has the flexibility to determine the set of SCs for which an AMR is performed, 

10 provided that this set includes the SCs for which the NRC has determined that an AMR is 

11 required. This is based on the Statements of Consideration for the license renewal rule 

12 (60 FR 22478). Therefore, the reviewer need not review all components that the applicant has 

13 identified as subject to an AMR because the applicant has the option to include more 

14 components than those required to be subject to an AMR pursuant to 10 CFR 54.21(a)(1). 

15 2.3.2 Acceptance Criteria 

16 The acceptance criteria for the areas of review define methods for determining whether the 

17 applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the 

18 applicant’s implementation of its methodology to be acceptable, the NRC staff should have 

19 reasonable assurance that there has been no omission of mechanical system components that 

20 are subject to an AMR. 

21 2.3.2.1 Components Within the Scope of Subsequent License Renewal 

22 Mechanical components are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are 

23  Safety-related systems, structures, and components (SSCs) that are relied upon to 

24 remain functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to 

25 ensure the following functions: 

26 — The integrity of the reactor coolant pressure boundary; 

27 — The capability to shut down the reactor and maintain it in a safe shutdown 

28 condition; or 

29 — The capability to prevent or mitigate the consequences of accidents that could 

30 result in potential offsite exposure comparable to the guidelines in 

31 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable. 

32  All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

33 any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii). 

34  All SSCs relied on in safety analyses or plant evaluations to perform a function that 

35 demonstrates compliance with NRC regulations for fire protection (10 CFR 50.48), 

36 environmental qualification (10 CFR 50.49), pressurized thermal shock (PTS) 

37 (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station 

38 blackout (10 CFR 50.63). 
2.3-3 

1 2.3.2.2 Components Subject to an Aging Management Review 

2 Mechanical components are subject to an AMR if they are within the scope of SLR and perform 

3 an intended function as defined in 10 CFR 54.4(b) without moving parts or a change in 

4 configuration or properties (“passive”), and are not subject to replacement based on a qualified 

5 life or specified time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)]. 

6 2.3.3 Review Procedures 

7 The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

8 additional information from the applicant regarding why a certain component was not identified 

9 by the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, 

10 the reviewer should provide a focused question that clearly explains what information is needed, 

11 why the information is needed, and how the information will allow the NRC staff to make its 

12 safety finding. In addition, other NRC staff members review the applicant’s scoping and 

13 screening methodology separately, following the guidance in Section 2.1. The reviewer should 

14 keep these other NRC staff members informed of findings that may affect their review of the 

15 applicant’s methodology. The reviewer should coordinate this sharing of information through 

16 the SLR project manager. 

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

18 2.3.3.1 Components Within the Scope of Subsequent License Renewal 

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

20 components that are within the scope of SLR. The Rule requires applicants to identify 

21 components that are within the scope of SLR and subject to an AMR. In the past, LRAs have 

22 included a table of components that are within the scope of license renewal; that information 

23 need not be submitted with SLRAs. Although a list of within the scope of SLR components will 

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

25 P&IDs, and review of the updated final safety analysis report (UFSAR) and other plant 

26 documents, what portion of the components are within the scope of SLR. The reviewer should 

27 check to see if any components exist that the NRC staff believes are within the scope of SLR 

28 but are not identified by the applicant as being subject to an AMR (and request that the 

29 applicant provide justification for omitting those components that are “passive” and “long-lived”). 

30 The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

31 conditions to determine the design basis for the SSCs. The design basis specifies the intended 

32 function(s) of the system(s). That intended function is used to determine the components within 

33 that system that are relied upon for the system to perform its intended functions. 

34 The reviewer should focus the review on those components that are not identified as being 

35 within the scope of SLR, especially the SLR boundary points and major flow paths. The 

36 reviewer should verify that the components do not have intended functions. Portions of the 

37 system identified as being within the scope of SLR by the applicant do not have to be reviewed 

38 because the applicant has the option to include more components within the scope than the 

39 rule requires. 

40 Further, the reviewer should select system functions described in the UFSAR that are required 

41 by 10 CFR 54.4 to verify that components having intended functions were not omitted from the 

42 scope of the rule. 
2.3-4 

1 For example, if a reviewer verifies that a portion of a system does not perform an intended 

2 function, is not identified as being subject to an AMR by the applicant, and is isolated from the 

3 portion of the system that is identified as being subject to an AMR by a boundary valve, the 

4 reviewer should verify that the boundary valve is subject to an AMR, or that the valve is not 

5 necessary for the within-scope portion of the system to perform its intended function. Likewise, 

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

7 components that are identified as not being within the scope of SLR to ensure they do not have 

8 intended functions that meet the requirements of 10 CFR 54.4. 

9 Section 2.1 contains additional guidance on the following: 

10  Commodity groups 

11  Complex assemblies 

12  Hypothetical failure 

13  Cascading 

14 If the reviewer has reviewed components in sufficient detail and does not identify any omissions 

15 of components within the scope of SLR, the reviewer would have reasonable assurance that the 

16 applicant has identified the components within the scope of SLR for the mechanical systems. 

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

18 review of the initial SLR applications and the basis for their disposition. 

19 2.3.3.2 Components Subject to an Aging Management Review 

20 In this step, the reviewer determines whether the applicant has properly identified the 

21 components subject to an AMR from among those that are within the scope of SLR renewal 

22 (i.e., those identified in Subsection 2.3.3.1). The reviewer should review selected components 

23 that the applicant has identified as within the scope of SLR but as not subject to an AMR. The 

24 reviewer should verify that the applicant has not omitted, from an AMR, components that 

25 perform intended functions without moving parts or without a change in configuration or 

26 properties and that are not subject to replacement on the basis of a qualified life or specified 

27 time period. 

28 Starting with the boundary verified in Subsection 2.3.3.1, the reviewer should sample 

29 components that are within the scope of SLR for that system, but were not identified by the 

30 applicant as subject to an AMR. Only components that are “passive” and “long-lived” are 

31 subject to an AMR. Table 2.1-5 is provided for the reviewer to assist in identifying whether 

32 certain components are “passive.” The applicant should justify omitting a component from an 

33 AMR that is within the scope of SLR at their facility and is listed as “passive” on Table 2.1-5. 

34 Although Table 2.1-5 is extensive, it may not be all-inclusive. Thus, the reviewer should use 

35 other available information sources, such as prior application reviews, to determine whether a 

36 component may be subject to an AMR. 

37 For example, an applicant has marked a boundary of a certain system that is within the scope of 

38 SLR. The marked-up diagram shows that there are pipes, valves, and air compressors within 

39 this boundary. The applicant has identified piping and valve bodies as subject to an AMR. 

40 Because Table 2.1-5 indicates that air compressors are not subject to an AMR, the reviewer 

41 should find the applicant’s determination acceptable. 
2.3-5 

1 Section 2.1 contains additional guidance on screening the following: 

2  Consumables 

3  Heat exchanger-intended functions 

4  Multiple functions 

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

6 AMR, the NRC staff would then have reasonable assurance that the applicant has identified the 

7 components subject to an AMR for the mechanical systems. 

8 Table 2.3-2 provides examples of mechanical components screening developed from lessons 

9 learned during the review of the initial SLR applications and bases for their disposition. 

10 If the applicant determines that a component is subject to an AMR, the applicant should also 

11 identify the component’s intended function, as defined in 10 CFR 54.4. Such functions must be 

12 maintained by any necessary AMRs. Table 2.3-3 provides examples of mechanical 

13 component-intended functions. 

14 2.3.4 Evaluation Findings 

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

16 provisions of the Standard Review Plan for Review of Subsequent License Renewal 

17 Applications for Nuclear Power Plants (SRP-SLR), then the NRC staff’s evaluation would 

18 support conclusions of the following type, to be included in the SER: 

19 On the basis of its review, as discussed above, the NRC staff concludes that 

20 there is reasonable assurance that the applicant has appropriately identified the 

21 mechanical system components within the scope of subsequent license renewal, 

22 as required by 10 CFR 54.4, and that the applicant has adequately identified the 

23 system components subject to an AMR in accordance with the requirements 

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

25 2.3.5 Implementation 

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

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

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

29 2.3.6 References 

30 None 
2.3-6 

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

Example Disposition 

Piping segment that provides 

structural support 

The safety-related/nonsafety-related boundary along a pipe 

run may occur at a valve location. The nonsafety-related 

piping segment between this valve and the next seismic 

anchor provides structural support in a seismic event. This 

piping segment is within the scope of SLR. 

Containment heating and 

ventilation system ductwork 

downstream of the fusible 

links providing cooling to the 

steam generator compartment 

and reactor vessel annulus 

This nonsafety-related ductwork provides cooling to support 

the applicant’s environmental qualification program. However, 

the failure of the cavity cooling system ductwork will not 

prevent the satisfactory completion of any critical safety 

function during and following a DBE. Thus, this ductwork is 

not within the scope of SLR. 

Standpipe installed inside the 

fuel oil storage tank 

The standpipe as described in the applicant’s CLB ensures 

that there is sufficient fuel oil reserve for the emergency diesel 

generator to operate for the number of days specified in the 

plant technical specifications following DBEs. Therefore, this 

standpipe is within the scope of SLR. 

Insulation on boron 

injection tank 

The temperature is high enough that insulation is not 

necessary to prevent boron precipitation. The plant technical 

specifications require periodic verification of the tank 

temperature. Thus, the insulation is not relied on to ensure the 

function of the emergency system and is not within the scope 

of SLR. 

Pressurizer spray head The spray head is not credited for the mitigation of any 

accidents addressed in the UFSAR accident analyses for 

many plants. The function of the pressurizer spray is to 

reduce reactor coolant system pressure during normal 

operating conditions. However, some plants rely on this 

component for pressure control to achieve cold shutdown 

during certain fire events. Failure of the spray head should be 

evaluated in terms of any possible damage to surrounding 

safety grade components, in addition to the need for spray. 

Therefore, this component should be evaluated on a 

plant-specific basis. 
2.3-7 

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

Example Disposition 

Diesel engine jacket water heat exchanger 

and portions of the diesel fuel oil system and 

starting air system supplied by a vendor on a 

diesel generator skid 

These are “passive,” “long-lived” components 

having intended functions. They are subject to 

an AMR for SLR even though the diesel 

generator is considered “active.” 

Fuel assemblies The fuel assemblies are replaced at regular 

intervals based on the fuel cycle of the plant. 

They are not subject to an AMR. 

Valve internals (such as disk and seat) 10 CFR 54.21(a)(1)(i) excludes valves, other 

than the valve body, from AMR. The 

statements of consideration of the license 

renewal rule provide the basis for excluding 

SCs that perform their intended functions with 

moving parts or with a change in configuration 

or properties. Although the valve body is 

subject to an AMR, valve internals are not. 
2.3-8 

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

Component Intended Function*

Piping Pressure boundary 

Valve body Pressure boundary 

Pump casing Pressure boundary 

Orifice Pressure boundary flow restriction 

Heat exchanger Pressure boundary heat transfer 

Reactor vessel internals Structural support of fuel assemblies, control 

rods, and incore instrumentation, to maintain 

core configuration and flow distribution 

*The component-intended functions are those that support the system-intended functions. For example, a heat 

exchanger in the spent fuel cooling system has a pressure boundary-intended function, but may not have a heat 

transfer function. Similarly, not all orifices have flow restriction as an intended function. 

 
2.4-1 

1 2.4 Scoping and Screening Results: Structures 

2 Review Responsibilities 

3 Primary—Assigned branch(s) 

4 Secondary—None 

5 2.4.1 Areas of Review 

6 This section addresses the scoping and screening results of structures and structural 

7 components for subsequent license renewal (SLR). Typical structures include the following: 

8  The primary containment structure; 

9  Building structures (such as the intake structure, diesel generator building, auxiliary 

10 building, and turbine building); 

11  Component supports (such as cable trays, pipe hangers, elastomer vibration isolators, 

12 equipment frames and stanchions, and heating, ventilation, and air conditioning (HVAC) 

13 ducting supports); 

14  Non-safety-related structures whose failure could prevent safety-related systems, 

15 structures, and components (SSCs) from performing their intended functions (e.g., 

16 seismic Category II structures over Category I structures). 

17 Typical structural components include the following: (i) liner plates, (ii) walls, (iii) floors, 

18 (iv) roofs, (v) foundations, (vi) doors, (vii) beams, (viii) columns, and (ix) frames. 

19 Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to 

20 identify and list structures and components (SCs) subject to an aging management review 

21 (AMR). These are “passive,” “long-lived” SCs that are within the scope of SLR. In addition, 

22 10 CFR 54.21(a)(2) requires an applicant to describe and justify the methods used to identify 

23 these SCs. The U.S. Nuclear Regulatory Commission (NRC) staff reviews the applicant’s 

24 methodology separately following the guidance in Section 2.1. To verify that the applicant has 

25 properly implemented its methodology, the NRC staff focuses its review on the implementation 

26 results. Such a focus allows the NRC staff to confirm that there is no omission of structures that 

27 are subject to an AMR by the applicant. If the review identifies no omission, the NRC staff has 

28 the basis to find that there is reasonable assurance that the applicant has identified the SCs that 

29 are subject to an AMR. 

30 An applicant should list all plant-level systems and structures. On the basis of the design basis 

31 events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information 

32 relating to nonsafety-related systems and structures and certain regulated events, the applicant 

33 should identify those plant-level systems and structures within the scope of SLR, as defined in 

34 10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. The NRC 

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

36 Section 2.2. 

37 For structures that are within the scope of SLR, an applicant must identify the SCs that are 

38 “passive” and “long-lived” in accordance with 10 CFR 54.21(a)(1)(i) and (ii). These “passive,” 
2.4-2 

1 “long-lived” SCs are subject to an AMR (“screening”). The applicant’s methodology 

2 implementation results for identifying SCs subject to an AMR is the area of review. 

3 The applicant has the flexibility to determine the set of SCs for which an AMR is performed, 

4 provided that this set includes the SCs for which the NRC has determined that an AMR is 

5 required. This flexibility is described in the statements of consideration for the License Renewal 

6 Rule (60 FR 22478). Therefore, the reviewer should not focus the review on structural 

7 components that the applicant has already identified as subject to an AMR because it is 

8 an applicant’s option to include more SCs than those subject to an AMR, pursuant to 

9 10 CFR 54.21(a)(1). Rather, the reviewer should focus on those SCs that are not included by 

10 the applicant as subject to an AMR to ensure that they do not perform an intended function as 

11 defined in 10 CFR 54.4(b) or are not “passive” and “long-lived.” 

12 2.4.2 Acceptance Criteria 

13 The acceptance criteria for the areas of review define methods for determining whether the 

14 applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the 

15 applicant’s implementation of its methodology to be acceptable, the NRC staff should have 

16 reasonable assurance that there has been no omission of SCs that are subject to an AMR. 

17 2.4.2.1 Structural Components Subject to an Aging Management Review 

18 Structural components are within the scope of SLR as delineated in 10 CFR 54.4(a) if they are 

19  Safety-related systems, structures, and components that are relied upon to remain 

20 functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to ensure the 

21 following functions: 

22 — The integrity of the reactor coolant pressure boundary; 

23 — The capability to shut down the reactor and maintain it in a safe shutdown 

24 condition; or 

25 — The capability to prevent or mitigate the consequences of accidents that 

26 could result in potential offsite exposure comparable to the guidelines in 

27 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable. 

28  All nonsafety-related systems, structures and components whose failure could prevent 

29 satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), 

30 or (iii). 

31  All systems, structures, and components relied on in safety analyses or plant evaluations 

32 to perform a function that demonstrates compliance with NRC regulations for fire 

33 protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized 

34 thermal shock (PTS) 

35 (10 CFR 50.61), anticipated transients without scram (ATWS) (10 CFR 50.62), and 

36 station blackout (SBO) (10 CFR 50.63). 

37 Structural components are subject to an AMR if they are within the scope of SLR and perform 

38 an intended function as defined in 10 CFR 54.4(b) without moving parts or a change in 
2.4-3 

1 configuration or properties (“passive”), and are not subject to replacement based on a qualified 

2 life or specified time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)].

3 2.4.3 Review Procedures 

4 The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

5 additional information from the applicant regarding why a certain structure was not identified by 

6 the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, 

7 the reviewer should provide a focused question that clearly explains what information is needed, 

8 why the information is needed, and how the information will allow the NRC staff to make its 

9 safety finding. In addition, other NRC staff members review the applicant’s scoping and 

10 screening methodology separately following the guidance in Section 2.1. The reviewer should 

11 keep these other NRC staff members informed of findings that may affect their review of the 

12 applicant’s methodology. The reviewer should coordinate this sharing of information through 

13 the SLR project manager. 

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

15 2.4.3.1 Structural Components Within the Scope of Subsequent License Renewal 

16 In this step, the NRC staff determines which structures and structural components are within the 

17 scope of subsequent license renewal. The Rule requires applicants to identify structures that 

18 are subject to an AMR, but not structures that are within the scope of subsequent license 

19 renewal. Whereas, in the past, LRAs have included a table of structures that are within the 

20 scope of license renewal, that information need not be submitted with future SLRAs. Although 

21 that information will be available at plant sites for inspection, the reviewer should determine 

22 through sampling of piping and instrumentation diagram piping and instrumentation diagram and 

23 through review of the updated final safety analysis report (UFSAR) and other plant documents 

24 what portion of the components are within the scope of SLR. The reviewer should check to see 

25 if any structures exist that the NRC staff believes are within the scope of SLR but are not 

26 identified by the applicant as being subject to an AMR (and request that the applicant provide 

27 justification for omitting those structures that are “passive” and “long-lived”). 

28 2.4.3.2 Structural Components Subject to an Aging Management Review 

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

30 AMR if they are within the scope of SLR. For each of the plant-level structures within the scope 

31 of SLR, an applicant should identify those structural components that have intended functions. 

32 For example, the applicant may identify that its auxiliary building is within the scope of SLR. For 

33 this auxiliary building, the applicant may identify the structural components of beams, concrete 

34 walls, blowout panels, etc., that are subject to an AMR. The applicant should justify omitting a 

35 component from an AMR that is within the scope of SLR at its facility and is listed as “passive” 

36 on Table 2.1-5. Although Table 2.1-5 is extensive, it may not be all-inclusive. Thus, the 

37 reviewer should use other available information, such as prior application reviews, to determine 

38 whether a component may be subject to an AMR. 

39 As set forth below, the reviewer should focus on individual structures not subject to an AMR, 

40 one at a time, to confirm that the structural components that have intended functions have been 

41 identified by the applicant. In a few instances, only portions of a particular building are within 

42 the scope of SLR. For example, a portion of a particular turbine building provides shelter for 

43 some safety-related equipment, which is an intended function, and the remainder of this 
2.4-4 

1 particular building does not have any intended functions. In this case, the reviewer should verify 

2 that the applicant has identified the relevant particular portion of the turbine building as being 

3 within the scope of SLR and subject to an AMR. 

4 The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

5 conditions to determine the design basis for the SSCs. The design basis specifies the intended 

6 function(s) of the system(s). That intended function is used to determine the components within 

7 that system that are relied upon for the system to perform its intended functions. 

8 The reviewer should focus the review on those structural components that have not been 

9 identified as being within the scope of SLR. For example, for a building within the scope of 

10 SLR, if an applicant did not identify the building roof as subject to an AMR, the reviewer should 

11 verify that the roof has no intended functions, such as a “Seismic Category II structures over 

12 Category I structures” concern in accordance with the plant’s CLB. The reviewer need not verify 

13 all structural components that have been identified as subject to an AMR by the applicant 

14 because the applicant has the option to include more structural components than the rule 

15 requires. 

16 Further, the reviewer should select functions described in the UFSAR to verify that structural 

17 components having intended functions were not omitted from the scope of the review. For 

18 example, if the UFSAR indicates that a dike within the fire pump house prevents a fuel oil fire 

19 from spreading to the electrically driven fire pump, the reviewer should verify that this dike has 

20 been identified as being within the scope of SLR. Similarly, if a nonsafety-related structure or 

21 component is included in the plant’s CLB as a part of the safe shutdown path resulting from the 

22 resolution of unresolved safety issue (USI) A-46 (Ref. 1), the reviewer should verify that the 

23 structure or component has been included within the scope of SLR. 

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

25 provides typical “passive” structural component-intended functions. 

26 The NRC staff has developed additional scoping/screening guidance (Ref. 2). For example, 

27 some structural components may be grouped together as a commodity, such as pipe hangers, 

28 and some structural components are considered consumable materials, such as sealants. 

29 Additional guidance on these and other components are contained in Section 2.1 for the 

30 following: 

31  Commodity groups 

32  Hypothetical failure 

33  Cascading 

34  Consumables 

35  Multiple functions 

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

37 AMR, the NRC staff would have reasonable assurance that the applicant has identified the 

38 components subject to an AMR for the structural systems. 

39 Table 2.4-1 provides examples of structural components scoping/screening lessons learned 

40 from the review of initial SLR applications and the basis for disposition. 
2.4-5 

1 If the applicant determines that a structural component may be subject to an AMR, the applicant 

2 should also identify the component’s intended functions, as defined in 10 CFR 54.4. Such 

3 functions must be maintained by any necessary aging management programs. 

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

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

6 components that are within the scope of SLR and subject to an AMR. 

7 2.4.4 Evaluation Findings 

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

9 provisions of the Standard Review Plan for Review of Subsequent License Renewal 

10 Applications for Nuclear Power Plants, then the NRC staff’s evaluation would support 

11 conclusions of the following type, to be included in the safety evaluation report: 

12 On the basis of its review, as discussed above, the NRC staff concludes that 

13 there is reasonable assurance that the applicant has appropriately identified the 

14 structural components subject to an AMR in accordance with the requirements 

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

16 2.4.5 Implementation 

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

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

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

20 2.4.6 References 

21 2. NRC. NUREG–1211, “Regulatory Analysis for Resolution of Unresolved Safety Issue 

22 A-46, Seismic Qualification of Equipment in Operating Plants.” Washington, DC: 

23 U.S. Nuclear Regulatory Commission. February 1987. 

24 3. NRC. NUREG–0933, “Resolution of Generic Safety Issues.” Supplement 32. 

25 Washington, DC: U.S. Nuclear Regulatory Commission. August 2008
2.4-6 

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

for Disposition 

Example Disposition 

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

turbine building roof will not result in the loss of any 

intended functions. The turbine building contains 

safety-related SSCs in the basement, which would remain 

sheltered and protected by several reinforced concrete 

floors if the turbine building roof were to degrade. 

Because this roof does not perform an intended function, 

it is not within the scope of subsequent license renewal. 

Post-tensioned containment 

tendon gallery 

The intended function of the post-tensioning system is to 

impose compressive forces on the concrete containment 

structure to resist the internal pressure resulting from a 

DBA with no loss of structural integrity. Although the 

tendon gallery is not relied on to maintain containment 

integrity during DBEs, operating experience indicates that 

water infiltration and high humidity in the tendon gallery 

can contribute to a significant aging effect on the vertical 

tendon anchorages that could potentially result in loss of 

the ability of the post-tensioning system to perform its 

intended function. However, containment inspections 

provide reasonable assurance that the tendon 

anchorages, including those in the gallery, will continue to 

perform their intended functions. Because the tendon 

gallery itself does not perform an intended function, it is 

not within the scope of subsequent license renewal. 

Water-stops Ground water leakage into the auxiliary building could 

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

leakage may cause flooding of equipment within the 

scope of subsequent license renewal. (The plant’s 

UFSAR discusses the effects of flooding.) The waterstops perform their functions without moving parts or a 

change in configuration, and they are not typically 

replaced. Thus, the water-stops are subject to an AMR. 

However, they need not be called out explicitly in the 

scoping/screening results if they are included as parts of 

structural components that are subject to an AMR. 
2.5-1 

1 2.5 Scoping and Screening Results: Electrical And Instrumentation and 

2 Controls Systems

3 Review Responsibilities 

4 Primary—Assigned branch(s) 

5 Secondary—None 

6 2.5.1 Areas of Review 

7 This review plan section addresses the electrical and instrumentation and control (I&C) scoping 

8 and screening results for subsequent license renewal (SLR). Typical electrical and I&C 

9 components that are subject to an aging management review (AMR) for SLR include electrical 

10 cables and connections. 

11 Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(1) requires an applicant to 

12 identify and list structures and components (SCs) subject to an AMR. These are “passive,” 

13 “long-lived” SCs that are within the scope of SLR. In addition, 10 CFR 54.21(a)(2) requires an 

14 applicant to describe and justify the methods used to identify these SCs. The U.S. Nuclear 

15 Regulatory Commission (NRC) staff reviews the applicant’s methodology separately following 

16 the guidance in Section 2.1. To verify that the applicant has properly implemented its 

17 methodology, the NRC staff focuses its review on the implementation results. Such a focus 

18 allows the NRC staff to confirm that there is no omission of electrical and I&C components that 

19 are subject to an AMR by the applicant. If the review identifies no omission, the NRC staff has 

20 the basis to find that there is reasonable assurance that the applicant has identified the 

21 electrical and I&C components that are subject to an AMR. 

22 An applicant should list all plant-level systems and structures. On the basis of the design basis 

23 events (DBEs) considered in the plant’s current licensing basis (CLB) and other CLB information 

24 relating to nonsafety-related systems and structures and certain regulated events, the applicant 

25 would identify those plant-level systems and structures that are within the scope of SLR, as 

26 defined in 10 CFR 54.4(a). This is “scoping” of the plant-level systems and structures for SLR. 

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

28 guidance in Section 2.2. 

29 For an electrical and I&C system that is within the scope of SLR, an applicant may not identify 

30 the specific electrical and I&C components that are subject to an AMR. For example, an 

31 applicant may not “tag” each specific length of cable that is “passive” and “long-lived,” and 

32 performs an intended function as defined in 10 CFR 54.4(b). Instead, an applicant may use the 

33 so-called “plant spaces” approach (Ref. 1), which is explained below. The “plant spaces” 

34 approach provides efficiencies in the AMR of electrical equipment located within the same plant 

35 space environment. 

36 Under the “plant spaces” approach, an applicant would identify all “passive,” “long-lived” 

37 electrical equipment within a specified plant space as subject to an AMR, regardless of whether 

38 these components perform any intended functions. For example, an applicant could identify all 

39 “passive,” “long-lived” electrical equipment located within the turbine building (“plant space”) as 

40 subject to an AMR for SLR. In the subsequent AMR, the applicant would evaluate the 

41 environment of the turbine building to determine the appropriate aging management activities 

42 for this equipment. The applicant has options to further refine this encompassing scope on an 
2.5-2 

1 as-needed basis. For this example, if the applicant identified elevated temperatures in a 

2 particular area within the turbine building, the applicant may elect to further refine the scope in 

3 this particular area by (1) identifying electrical equipment that is not subject to an AMR and 

4 (2) excluding this equipment from the AMR. In this case, the excluded electrical equipment 

5 would be reported in the application as not being subject to an AMR. 

6 10 CFR 54.21(a)(1)(i) provides many examples of electrical and I&C components that are not 

7 considered to be “passive” and are not subject to an AMR for SLR. Therefore, the applicant is 

8 expected to identify only a few electrical and I&C components, such as electrical penetrations, 

9 cables, and connections that are “passive” and subject to an AMR. However, the time-limited 

10 aging analysis (TLAA) evaluation requirements in 10 CFR 54.21(c) apply to environmental 

11 qualification of electrical equipment, which is not limited to “passive” components. 

12 An applicant has the flexibility to determine the set of electrical and I&C components for which 

13 an AMR is performed, provided that this set includes the electrical and I&C components for 

14 which the NRC has determined an AMR is required. This is based on the statements of 

15 consideration for the License Renewal Rule (60 FR 22478). Therefore, the reviewer need not 

16 review all components that the applicant has identified as subject to an AMR because 

17 the applicant has the option to include more components than those required by 

18 10 CFR 54.21(a)(1). 

19 2.5.2. Acceptance Criteria 

20 The acceptance criteria for the areas of review define methods for determining whether the 

21 applicant has met the requirements of NRC regulations in 10 CFR 54.21(a)(1). For the 

22 applicant’s implementation of its methodology to be acceptable, the NRC staff should have 

23 reasonable assurance that there has been no omission of electrical and I&C system 

24 components that are subject to an AMR. 

25 2.5.2.1 Components Within the Scope of Subsequent License Renewal 

26 Electrical and I&C components are within the scope of SLR as delineated in 

27 10 CFR 54.4(a) if they are 

28  Safety-related systems, structures, and components (SSCs) that are relied upon to 

29 remain functional during and following DBEs [as defined in 10 CFR 50.49(b)(1)] to 

30 ensure the following functions: 

31 — The integrity of the reactor coolant pressure boundary; 

32 — The capability to shut down the reactor and maintain it in a safe shutdown 

33 condition; or 

34 — The capability to prevent or mitigate the consequences of accidents that could 

35 result in potential offsite exposure comparable to the guidelines in 

36 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2) or 10 CFR 100.11, as applicable. 

37  All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

38 any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii) or (iii). 
2.5-3 

1  All SSCs relied on in safety analyses or plant evaluations to perform a function that 

2 demonstrates compliance with NRC regulations for fire protection (10 CFR 50.48), 

3 environmental qualification (10 CFR 50.49), pressurized thermal shock (PTS) 

4 (10 CFR 50.61), anticipated transients without scram (ATWS) (10 CFR 50.62), and 

5 station blackout (SBO) (10 CFR 50.63). 

6 2.5.2.1.1 Components Within the Scope of SBO (10 CFR 50.63) 

7 Both the offsite and onsite power systems are relied upon to meet the requirements of the SBO 

8 Rule. This includes the following: 

9  The onsite power system meeting the requirements under 10 CFR 54.4(a)(1) 

10 (safety-related systems) 

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

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

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

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

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

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

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

18 the transformers themselves, the intervening overhead or underground circuits between 

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

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

21 based on the plant-specific CLB, regulatory requirements, and offsite power 

22 design configurations. 

23 2.5.2.2 Components Subject to an Aging Management Review 

24 Electrical and I&C components are subject to an AMR if they are within the scope of SLR and 

25 perform an intended function as defined in 10 CFR 54.4(b) without moving parts or without a 

26 change in configuration or properties (“passive”), and are not subject to replacement based on a 

27 qualified life or specified time period (“long-lived”) [10 CFR 54.21(a)(1)(i) and (ii)]. 

28 2.5.3 Review Procedures 

29 The reviewer verifies the applicant’s scoping and screening results. If the reviewer requests 

30 additional information from the applicant regarding why a certain component was not identified 

31 by the applicant as being within the scope of SLR or subject to an AMR for the applicant’s plant, 

32 the reviewer should provide a focused question that clearly explains what information is needed, 

33 why the information is needed, and how the information will allow the NRC staff to make its 

34 safety finding. In addition, other NRC staff members review the applicant’s scoping and 

35 screening methodology separately following the guidance in Section 2.1. The reviewer should 

36 keep these other NRC staff members informed of findings that may affect their review of the 

37 applicant’s methodology. The reviewer should coordinate this sharing of information through 

38 the SLR project manager. 

39 The reviewer should verify that an applicant has identified in the SLR application the electrical 

40 and I&C components that are subject to an AMR for its plant. The review procedures are 

41 presented below and assume that the applicant has performed “scoping” and “screening” of 
2.5-4 

1 electrical and I&C system components in that sequence. However, the applicant may elect to 

2 perform “screening” before “scoping,” which is acceptable because, regardless of the sequence, 

3 the end result should encompass the electrical and I&C components that are subject to 

4 an AMR. 

5 Some of the electrical equipment that is in the scope of 10 CFR 50.49 that have a qualified life 

6 of 40 years or greater are also within the scope of SLR under 10 CFR 54.4(a)(3). They have 

7 already been identified by licenses under 10 CFR 50.49(b). Licensees may rely upon their 

8 listing of environmental qualification (EQ) equipment, as required by 10 CFR 50.49(d), for the 

9 purposes of identifying electrical equipment satisfying 10 CFR 54.4(a)(3) that is also within the 

10 scope of 10 CFR 50.49 (60 FR 22466). However, the license renewal rule has a requirement 

11 [10 CFR 54.21(c)] on the evaluation of TLAAs, including EQ (10 CFR 50.49). EQ equipment 

12 is not limited to “passive” equipment. The applicant may identify EQ equipment separately 

13 for TLAA evaluation and not include such equipment as subject to an AMR under 

14 10 CFR 54.21(a)(1). The EQ equipment identified for TLAA evaluation would include the 

15 “passive” EQ equipment subject to an AMR. The TLAA evaluation would ensure that the EQ 

16 equipment would be functional for the period of extended operation. The NRC staff reviews the 

17 applicant’s EQ TLAA evaluation separately following the guidance in Section 4.4. 

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

19 2.5.3.1 Components Within the Scope of Subsequent License Renewal 

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

21 components that are within the scope of SLR. The Rule requires that the subsequent license 

22 renewal application (SLRA) identify and list components that are within the scope of SLR and 

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

24 are within the scope of license renewal, generally that information need not be submitted with 

25 future SLRAs. Although that information will be available at plant sites for inspection, the 

26 reviewer must determine, through sampling of one-line diagrams and through review of the 

27 updated final safety analysis report (UFSAR) and other plant documents, what portion of the 

28 components are within the scope of SLR. The reviewer must check to see if any components 

29 exist that the NRC staff believes are within the scope but are not identified by the applicant as 

30 being subject to AMR (any request that the applicant provide justification for omitting those 

31 components that are “passive” and “long-lived”). 

32 The reviewer should use the UFSAR, orders, applicable regulations, exemptions, and license 

33 conditions to determine the design basis for the SSCs. The design basis specifies the intended 

34 function(s) of the system(s). That intended function is used to determine the components within 

35 that system that are required for the system to perform its intended functions. 

36 The applicant may use the “plant spaces” approach in scoping electrical and I&C components 

37 for SLR. In the “plant spaces” approach, an applicant may indicate that all electrical and I&C 

38 components located within a particular plant area (“plant space”), such as the containment and 

39 auxiliary building, are within the scope of SLR. The applicant may also indicate that all electrical 

40 and I&C components located within another plant area (“plant space”), such as the warehouse, 

41 are not within the scope of SLR. Table 2.5-1 contains examples of this “plant spaces” approach 

42 and the corresponding review procedures. 

43 The applicant would use the “plant spaces” approach for the subsequent AMR of the electrical 

44 and I&C components. The applicant would evaluate the environment of the “plant spaces” to 
2.5-5 

1 determine the appropriate aging management activities for equipment located there. The 

2 applicant has the option to further refine this encompassing scope on an as-needed basis. For 

3 example, if the applicant identified elevated temperatures in a particular area within a building 

4 (“plant space”), the applicant may elect to identify only those “passive,” “long-lived” electrical 

5 and I&C components that perform an intended function in this particular area as subject to an 

6 AMR. This approach of limiting the “plant spaces” is consistent with the “plant spaces” 

7 approach. In this case, the reviewer verifies that the applicant has specifically identified the 

8 electrical and I&C components that may be within the scope of SLR in these limited “plant 

9 spaces.” The reviewer should verify that the electrical and I&C components that the applicant 

10 has elected to further exclude do not indeed have any intended functions as defined in 

11 10 CFR 54.4(b). 

12 Section 2.1 contains additional guidance on scoping the following: 

13  Commodity groups 

14  Complex assemblies 

15  Scoping events 

16  Hypothetical failure 

17  Cascading 

18 If the reviewer does not identify any omissions of components from those that are within the 

19 scope of SLR, the NRC staff would have reasonable assurance that the applicant has identified 

20 the components within the scope of SLR for the electrical and I&C systems. 

21 2.5.3.2 Components Subject to an Aging Management Review 

22 In this step, the reviewer determines whether the applicant has properly identified the 

23 components subject to an AMR from among those which are within the scope of SLR (i.e., those 

24 identified in Subsection 2.5.3.1). The reviewer should review selected components that the 

25 applicant has identified as being within the scope of SLR to verify that the applicant has 

26 identified these components as being subject to an AMR if they perform intended functions 

27 without moving parts or without a change in configuration or properties and are not subject to 

28 replacement on the basis of a qualified life or specified time period. The description of “passive” 

29 may also be interpreted to include structures and components that do not display “a change in 

30 state.” 

31 Only components that are “passive” and “long-lived” are subject to an AMR. Table 2.1-5 lists 

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

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

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

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

36 AMR. Although Table 2.1-5 is extensive, it may not be all-inclusive. Thus, the reviewer should 

37 use other available information sources, such as prior application reviews, to determine whether 

38 a component may be subject to an AMR. 

39 Section 2.1 contains additional guidance on screening the following: 

40  Consumables 

41  Multiple intended functions 
2.5-6 

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

2 AMR, the NRC staff would have reasonable assurance that the applicant has identified the 

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

4 2.5.4 Evaluation Findings 

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

6 provisions of the Standard Review Plan for Review of Subsequent License Renewal 

7 Applications for Nuclear Power Plants, then the NRC staff’s evaluation would support 

8 conclusions of the following type, to be included in the safety evaluation report. 

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

10 reasonable assurance that the applicant has appropriately identified the electrical and 

11 instrumentation and controls system components subject to an AMR in accordance with the 

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

13 2.5.5 Implementation 

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

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

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

17 2.5.6 References 

18 1. SNL. SAND96-0344, “Aging Management Guideline for Commercial Nuclear Power 

19 Plants-Electrical Cable and Terminations.” Albuquerque, New Mexico: Sandia National 

20 Laboratories. September 1996. 
2.5-7 

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

Corresponding Review Procedures

Example Review Procedures 

An applicant indicates that all 

electrical and I&C components 

on site are within the scope of 

SLR. 

This is acceptable, and a review is not necessary because all 

electrical and I&C components are included without 

exception and would include those required by the rule. 

An applicant indicates that all 

electrical and I&C components 

located in seven specific 

buildings (containment, auxiliary 

building, turbine building, etc.) 

are within the scope of SLR. 

The reviewer should review electrical systems and 

components in areas outside of these seven buildings (“plant 

spaces”). The reviewer should verify that the applicant has 

included any direct-buried cables in trenches between these 

buildings as within the scope of SLR if they perform an 

intended function. The reviewer should also select buildings 

other than the seven indicated (for example, the radwaste 

facility) to verify that they do not contain any electrical and 

I&C components that perform any intended functions. 

An applicant indicates that all 

electrical and I&C components 

located onsite, except for the 

525 kV switchyard, 230 kV 

transmission lines, radwaste 

facility, and 44 kV substation, 

are within the scope of SLR. 

The reviewer should select the specifically excluded “plant 

spaces” (that is, the 525 kV switchyard, 230 kV transmission 

lines, radwaste facility, and 44 kV substation) to verify that 

they do not contain any electrical and I&C components that 

perform any intended functions. 

3.0-1 

1 3 AGING MANAGEMENT REVIEW 

2 3.0 Integrated Plant Assessments and Aging Management Reviews 

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

4 safety review of the subsequent license renewal application (SLRA) is responsible for assigning 

5 to appropriate NRC Office of Nuclear Reactor Regulation divisions the review or audit of aging 

6 management reviews (AMRs) of systems, structures and components (SSCs) or aging 

7 management programs (AMPs) identified in the applicant’s SLRA. The PM documents to which 

8 organization each AMR or AMP is assigned. The assigned AMRs and AMPs are reviewed per 

9 the criteria described in Sections 3.1 through 3.6 of this Standard Review Plan for Review of 

10 Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR), for review of 

11 SLRAs, as directed by the scope of each of these sections. Chapter 4 of this standard review 

12 plan provides guidelines for using time-limited aging analyses (TLAAs) as the basis for 

13 evaluating and managing aging effects by analysis. Specifically, Section 4.1 of this standard 

14 review plan (SRP) provides the NRC staff’s guidance for identifying TLAAs in accordance with 

15 the requirements in Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1) and the 

16 definitions of TLAAs in 10 CFR 54.3. TLAAs are reviewed in accordance with the acceptance 

17 criteria and guidance described in Sections 4.2 through 4.7 of this SRP. 

18 Review of the AMPs requires assessment of 10 program elements as defined in this SRP-SLR. 

19 The NRC division assigned the AMP reviews the 10 program elements to verify their technical 

20 adequacy. For three of the 10 program elements (corrective actions, confirmation process, and 

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

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

23 Safety Analysis Report (FSAR) Supplement to expand the scope of its 10 CFR Part 50, 

24 Appendix B program to address the associated program elements for each AMP. If the 

25 applicant chooses alternate means of addressing these three program elements (i.e., use of a 

26 process other than the applicant’s 10 CFR Part 50, Appendix B program) the NRC division 

27 assigned to review the AMP should request that the division responsible for QA review the 

28 applicant’s proposal on a case-specific basis. 

29 Table 3.01 is a supplement to the FSAR and contains a list of programs that are applicable to 

30 each SRP-SLR and subsection. It also contains the programs that are applicable to managing 

31 the aging effects associated with various systems. 

32 3.0.1 Background on the Types of Reviews 

33 Section–54.21(a)(3) to 10 CFR Part 54 requires -the application to demonstrate, for systems, 

34 structures, and components (SSCs) within the scope of license renewal and subject to an AMR 

35 pursuant to 10 CRF 54.21(a)(1), that the effects of aging are adequately managed so that the 

36 intended function(s) are maintained consistent with the current licensing basis (CLB) for the 

37 subsequent period of extended operation. This AMR consists of identifying the material, 

38 environment, aging effects, and the AMP(s) credited for managing the aging effects. 

39 Sections 3.1 through 3.6 of this SRP-SLR describe how the AMRs and AMPs are reviewed. In 

40 this SRP-SLR, Subsection 3.X.2 (where X denotes number 1–6) presents the acceptance 

41 criteria describing methods to determine whether the applicant has met the requirements of the 

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

43 be followed.
3.0-2 

1 The AMR line items in the 3.X-1 tables provide a generic list of AMRs for groups of components 

2 that may be included in the reactor coolant system, emergency safety feature systems, auxiliary 

3 systems, steam and power conversion systems, structures and structural components, and 

4 electrical systems of an applicant’s pressurized water reactor (PWR) or boiling water reactor 

5 (BWR) plant design. The AMR items are provided in a column-based format that accomplishes 

6 the following objectives: 

7  New, Modified, Deleted Item: The description of this column identifies whether the AMR 

8 line item is new, was modified, or deleted. The NRC will publish the technical bases for 

9 these new, modified, and deleted AMR items in a NUREG containing the disposition of 

10 public comments and the technical bases for changes in the guidance documents when 

11 the final subsequent license renewal (SLR) guidance documents are published. 

12  “ID” column: The description for this column provides an identification number for the 

13 AMR item of a given commodity grouping of components that have common materials of 

14 fabrication, environmental conditions, and aging effects. 

15  “Type” column: The description for this column identifies whether the specific AMR item 

16 in the table is applicable to BWR or PWR plant designs. 

17  “Component” column: The description for this column identifies the specific components 

18 that are within the scope of the commodity grouping in the AMR item and the materials 

19 of fabrication and environmental conditions that are applicable to the components in the 

20 AMR item. 

21  “Aging Effect/Mechanism” column: The description for this column identifies the aging 

22 effects and mechanisms that are applicable to the material-environmental combinations 

23 for the components in the commodity grouping of the AMR item. 

24  “Aging Management Program/TLAA” column: The description for this column provides 

25 AMPs or TLAAs that may be used to manage the aging effects that apply to the 

26 components in the commodity grouping of the AMR item and to demonstrate compliance 

27 with the aging management requirement in 10 CFR54.21(a)(3). 

28  “Further Evaluation” column: The description for this column identifies whether the AMP 

29 or TLAA recommended in the “Aging Management Program/TLAA” column of the AMR 

30 item requires additional evaluation (further evaluation) by an applicant adopting the AMR 

31 item. This column also references specific subsection(s) in SRP-SLR Section 3.1.2.2 

32 that applies to the evaluation of the components in the commodity grouping of the 

33 AMR item. 

34  “GALL-SLR Item” column: The description for this column identifies the component35 specific AMR items in the Generic Aging Lessons Learned for Subsequent License 

36 Renewal (GALL-SLR) Report that derives from the commodity-group-based item in the 

37 SRP-SLR AMR table. 

38 The GALL-SLR Report is a technical basis document to the SRP-SLR and provides generic 

39 AMR and AMP guidance that may be used as part of the bases for developing an SLRA. As 

40 such, the GALL-SLR Report contains an acceptable method that may be used to assist an 

41 applicant in: (a) developing the integrated plant assessment (IPA) for an SLRA, as required by 

42 10 CFR 54.21(a); (b) identifying those components and structures that are required to be within 
3.0-3 

1 the scope of an AMR, as required by 10 CFR 54.21(a)(1); and (c) managing those aging effects 

2 that are applicable to these SSCs, as required by 10 CFR 54.21(a)(3). An applicant may 

3 propose an alternative method for performing the IPA. Therefore, the use of the GALL-SLR 

4 Report is not required; however, its use should facilitate both preparation of a SLRA by an 

5 applicant and timely, uniform review by the NRC staff. If the GALL-SLR report is used for the 

6 development of an SLRA, the GALL-SLR Report should be treated as an NRC-approved 

7 topical report. 

8 The GALL-SLR Report contains an AMR evaluation of a large number of SCs that may be in the 

9 scope of a typical SLRA and may need to be the subject of an AMR in accordance with 

10 requirements in 10 CFR 54.21(a)(1). The AMR results documented in the GALL-SLR Report 

11 indicate that many existing, typical generic AMPs are adequate to manage aging effects for 

12 particular structures or components without change. The GALL-SLR Report also contains 

13 recommendations on specific areas for which generic existing programs should be augmented 

14 for SLRAs and documents the technical basis for each such determination. In addition, the 

15 GALL-SLR Report identifies certain SCs that may or may not be subject to particular aging 

16 effects, and for which industry groups are developing generic AMPs or investigating whether 

17 aging management is warranted. The ultimate generic resolution of such an issue may need 

18 NRC review and approval for plant-specific implementation, as indicated in a plant-specific 

19 FSAR supplement, and reflected in the safety evaluation report (SER) associated with a 

20 particular SLRA. 

21 The GALL-SLR Report does not address scoping of SSCs for subsequent license renewal 

22 (SLR). The determination of SSCs that need to be within the scope of SLR is plant-specific 

23 aspect of the application and is required to be performed in accordance with the requirements in 

24 10 CFR 54.4. Consistent with the scoping guidelines in Chapter 2 of this SRP-SLR Report, the 

25 scoping results for an SLRA are dependent on the plant design and CLB. Therefore, the 

26 inclusion of a certain structure or component in a given AMR line item of the GALL-SLR 

27 Report does not mean that this particular structure or component is within the scope of SLR for 

28 all plants. 

29 Conversely, the omission of a certain structure or component in the GALL-SLR Report does not 

30 mean that a particular structure or component in the plant design is not within the scope of the 

31 SLRA or does not need to be the subject of an AMR in accordance with the requirements in 

32 10 CFR 54.21(a)(1). The AMR line items in the SRP-SLR and GALL-SLR Report may not 

33 provide a comprehensive list of all structures of components that need to be within the subject 

34 of an AMR or a comprehensive list of all potential aging effects that may be applicable to those 

35 structures or components as being the subject of an AMR. Therefore, as has been the practice 

36 for initial license renewal applications (LRAs), plant-specific AMRs should be performed if 

37 additional aging effects (not referenced in the SRP-SLR and GALL-SLR reports) are applicable 

38 to the design of a specific structure or component subject to an AMR. 

39 As indicated in the bulleted list above, the specific AMR line items in Chapters II–VIII of the 

40 GALL-SLR Report derive from and are identified in the AMR line items of the 3.X-2 tables of the 

41 SRP-SLR. The AMR line items in GALL-SLR Report are formatted in a manner that is 

42 analogous (but not identical) to the format of the AMR line items in the SRP-SLR. In addition, 

43 as indicated above, the “Further Evaluation” column in the AMR line items of the 3.X-1 tables of 

44 this report and the AMR tables (Chapters II through VIII of the GALL-SLR Report) establish 

45 whether the aging management bases in those AMR line items need to be the subject of further 

46 assessment by the applicant (i.e., the subject of “further evaluations”). The “further evaluation” 

47 topics and the acceptance criteria for satisfying these “further evaluations” are described in the 
3.0-4 

1 3.X.2.2 subsections of this report. The related review procedures for these “further evaluation” 

2 topics are provided in the 3.X.3.2 subsections of this report. 

3 Therefore, for SCs in the plant design that are required to be scoped into the SLRA and subject 

4 to an AMR, the applicant may use the AMR line items in the 3.X-1 tables of the SRP-SLR, and 

5 the AMR line items in the GALL-SLR Report referenced in these SRP-SLR tables, as a basis for 

6 comparison to the design of the SCs in the plant design. If this method is used for development 

7 of the AMR, the applicant may adopt those AMR items in the SRP-SLR and GALL-SLR Reports 

8 that are applicable to the design of the SCs in the plant in order to aid the applicant in identifying 

9 those aging effects that are applicable to the structures or components. For those AMR items in 

10 the SLRA that are designated as being consistent with the SRP-SLR and GALL-SLR Reports 

11 and are the subject of “further evaluation” aging management topics, the AMR should include 

12 the applicant’s bases on how those “further evaluation” criteria have been addressed and met, 

13 as applicable to the licensing basis and design basis for the plant’s design. 

14 As part of the development of the SLRA, the applicant should assess the AMPs in the 

15 GALL SLR Report. The applicant may choose to use an AMP that is consistent with the 

16 GALL SLR Report AMP, or may choose a plant-specific AMP. An applicant may reference the 

17 GALL-SLR Report in an SLRA to designate which programs at the applicant’s facility will be 

18 used to manage the effects of aging for specific structures or components, and how those 

19 programs correspond to the AMPs reviewed and approved in the GALL-SLR Report. If an 

20 applicant does take credit for a program in the GALL-SLR Report, it is incumbent on the 

21 applicant to ensure that the conditions and operating experience at the plant is bounded by the 

22 conditions and operating experience for which the GALL-SLR Report program was evaluated. If 

23 these bounding conditions are not met it is incumbent on the applicant to address the additional 

24 effects of aging and augment the AMP(s) in the GALL-SLR Report in the SLRA, as appropriate. 

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

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

27 exception to the GALL-SLR Report AMP should be described and justified. Exceptions are 

28 portions of the GALL-SLR Report AMP that the applicant does not intend to implement. 

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

30 all the program elements defined in the GALL-SLR Report AMP. If this is the situation, the 

31 applicant makes a commitment to augment the existing program to satisfy the GALL-SLR 

32 Report AMP elements prior to the subsequent period of extended operation. 

33 Enhancements are revisions or additions to existing AMPs that the applicant commits to 

34 implement prior to the subsequent period of extended operation. Enhancements include, but 

35 are not limited to, those activities needed to ensure consistency with the GALL-SLR Report 

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

37 For the programs submitted in the SLRA that the applicant claims are consistent with the 

38 GALL-SLR, the NRC staff will verify that the applicant’s programs are consistent with those 

39 described in the GALL-SLR Report and/or with plant conditions and operating experience during 

40 the performance of an AMP audit and review. The focus of the balance of the NRC staff review 

41 of a SLRA is on those programs that an applicant has enhanced to be consistent with the 

42 GALL-SLR Report, those programs for which the applicant has taken an exception to the 

43 program described in the GALL-SLR Report, and plant-specific programs not described in the 

44 GALL-SLR Report. 
3.0-5 

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

2 claims to be consistent with the GALL-SLR Report. The applicant may use a plant-specific AMP 

3 or plant-specific aging management activities as the basis for aging management of a specific 

4 structure or component. If plant-specific AMPs or aging management activities are used as the 

5 basis for aging management, the NRC staff reviews the AMPs or activities in accordance with 

6 the program element criteria that are defined in the SRP-SLR Appendix A.1, Subsection A.1.2.3. 

7 Reviews are also performed to address those AMRs or AMPs related to emergent issues, 

8 stated to be not consistent with the GALL-SLR Report, or based on an NRC-approved 

9 precedent (e.g., AMRs and AMPs addressed in an NRC SER of a previous SLRA) or technical 

10 or topical report. SRP-SLR Section 3.0.3 provides additional guidance on reviewing those 

11 GALL-based or plant-specific AMPs that are based on NRC-endorsed technical or topical 

12 reports. As a result of the criteria established in 10 CFR Part 54, the guidance provided in 

13 SRP-SLR, GALL-SLR Report, and the applicant’s exceptions and/or enhancements to a 

14 GALL-SLR Report AMP, the following types of AMRs and AMPs are audited or reviewed by the 

15 NRC staff. 

16 AMRs 

17  AMR results consistent with the GALL-SLR Report 

18  AMR results for which further evaluation is recommended 

19  AMR results not consistent with or not addressed in the GALL-SLR Report 

20 AMPs 

21  Consistent with the GALL-SLR Report AMPs 

22  Plant-specific AMPs 

23 FSAR Supplement 

24  Each SLRA AMP will provide an FSAR Supplement which defines changes to the FSAR 

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

26 the AMPs the applicant is crediting to satisfy 10 CFR 54.21(a)(3). 

27  The FSAR Supplement should also contain a commitment to implement the SLRA AMP 

28 enhancement prior to the subsequent period of extended operation. 

29 3.0.2 Applications With Approved Extended Power Uprates 

30 Extended power uprates (EPUs) are licensing actions that some licensees have recently 

31 requested the NRC staff to approve. This can affect aging management. In an NRC staff letter 

32 to the Advisory Committee on Reactor Safeguards, dated October 26, 2004 (ADAMS Accession 

33 No. ML042790085), the NRC Executive Director for Operation states that “All license renewal 

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

35 and its impact on AMPs for SCs before entering the subsequent period of extended operation.” 

36 One way for an applicant with an approved EPU to satisfy this criterion is to document its 

37 commitment to perform an operating experience review and its impact on AMPs for SSCs 

38 before entering the subsequent period of extended operation as part of its SLRA. Such licensee 

39 commitments should be documented in the NRC staff’s SER, written in support of issuing a 

40 renewed license. The NRC staff expects to impose a license condition on any renewed license 

41 to ensure that the applicant completes these activities no later than the committed date. EPU 
3.0-6 

1 impact on SSCs should be part of the SLR review. If necessary, the PM assigns a responsible 

2 group to address EPU. 

3 3.0.3 Aging Management Programs that Rely on Implementation of Nuclear 

4 Regulatory Commission-Approved Technical or Topical Reports 

5 The U.S. Nuclear Regulatory Commission (NRC) Office Instruction LIC-500, Revision 5, 

6 establishes the NRC’s current process expectations for applying the methodology in an 

7 NRC-endorsed or NRC-approved technical report or topical report (TR) to the CLB or current 

8 design basis of a licensed U.S. light-water reactor facility. The LIC-500 office instruction 

9 identifies that use of such reports may be subject to specific limitations or actions, which are 

10 identified and issued in the NRC’s safety evaluations (SEs) that are issued regarding on the TR 

11 methodologies. The LIC-500 office instruction states that it is the NRC’s expectation that 

12 licensees or applicants applying these types of reports to their CLBs or design bases will 

13 address or respond to those action items or limitations that were issued in the NRC staff’s SEs 

14 regarding the TR methodologies. 

15 Generic Aging Lessons Learned for Subsequent License Renewal Report(GALL-SLR) aging 

16 management programs (AMPs) that rely on the recommended activities in NRC-endorsed TRs 

17 identify those TRs that are within the scope of the AMPs. Examples of GALL-SLR AMPs that 

18 rely on NRC-approved industry reports include, but are not limited to, (1) GALL-SLR Report 

19 AMP XI.M4, “BWR ID Attachment Welds,” (2) GALL-SLR Report AMP XI.M5, “BWR Feedwater 

20 Nozzles,” (3) GALL-SLR Report AMP XI.M8, “BWR Penetrations,” and (4) GALL-SLR 

21 Report AMP XI.M9, “BWR Vessel Internals.” Plant-specific AMPs may also be based on 

22 NRC-approved TRs. 

23 For AMPs that rely on one or more NRC-endorsed TRs, the use of TR methodologies that are 

24 relied upon for aging management is subject to the applicant’s bases for resolving any 

25 limitations or action items that are placed on implementation of the applicable TR 

26 methodologies. Therefore, an applicant’s bases for resolving any limitations or actions items on 

27 the TRs is especially relevant to the applicant’s determination on whether the scope of the 

28 program, or other program elements in the AMP, will need to be augmented or enhanced 

29 beyond conformance with the recommended criteria, evaluations, and activities in the applicable 

30 TRs. Therefore, the AMPs should include the applicant’s bases for resolving any limitation or 

31 action items on the applicable TR methodologies, as documented in the NRC SE regarding the 

32 methodologies. If it is determined that the basis for resolving a specific TR limitation or 

33 applicant action item would result in the need for augmentation of the AMP beyond the criteria, 

34 evaluations, or activities recommended in the TRs, the applicant should enhance its AMPs 

35 accordingly to identify the TR guidance protocols or activities that will be impacted and the 

36 specific AMP program elements that will need to be enhanced or adjusted (as necessary and 

37 applicable to the CLB and design basis for the facility) as a result of the applicant’s basis for 

38 resolving the specific limitation or action item. Consistent with the recommendations in 

39 NEI 95-10, applicants may provide their bases for resolving the specific limitations or action 

40 items in Appendix C of their SLRAs. 

41 In addition, for AMPs that rely on these types of TRs, the recommended activities in these TRs 

42 may go beyond those activities that are within the scope of applicable NRC requirements 

43 (e.g., those requirements in any of the applicable Federal Acts, NRC regulations, plant 

44 operating license or technical specification requirements, or NRC-issued orders). 

45 Implementation of the TRs referenced in the AMPs does not relieve the applicant from 

46 complying with the applicable requirements, unless applicable Code reliefs, regulatory 
3.0-7 

1 exemptions, or notices of enforcement action are requested and granted by the NRC for the 

2 specific type of requirement that applies to the CLB. This is in addition to those aspects of the 

3 10 CFR Part 50, Appendix B program that may apply to the AMPs. 
3.0-8 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

XI.E1 

Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

The program provides reasonable assurance that the intended functions of electrical cable insulating material (e.g., power, 

control, and instrumentation) and connection insulating material that are not subject to the environmental qualification requirements of 10 CFR 50.49 are maintained consistent with the current licensing basis through the subsequent period of extended operation. The program is a cable and connection insulation material condition monitoring program that utilizes sampling. The component sampling methodology utilizes a population that includes a representative sample of in-scope electrical cable and connection types regardless of whether or not the component was included in a previous aging management or maintenance program. The technical basis for the sample selection is documented. The program applies to accessible electrical cable and connection electrical insulation material within the scope of license renewal including in-scope cables and connections subjected to an adverse localized environment. Accessible inscope electrical cable and connection electrical insulation material is visually inspected and tested for cable and connection insulation surface anomalies indicating signs of reduced electrical insulation resistance. Visual Inspection and testing may include thermography and one or more proven condition monitoring test methods applicable to the cable and connection insulation material. Electrical cable and connection insulation material test results are to be within the acceptance criteria, as identified in the applicant’s procedures. Visual inspection results show that accessible cable and connection insulation material are free from visual indications of surface abnormalities that indicate cable or connection electrical insulation aging effects exist. 

First inspection for license renewal completed prior to the subsequent period of extended operation 

GALL VI / SRP 3.6 
3.0-9 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

When acceptance criteria are not met, a determination is made as to whether the surveillance, inspection, or tests, including frequency intervals, need to be modified. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report.[The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E2 

Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits 

The program applies to electrical cables and connections (cable system) electrical insulation material used in circuits with sensitive, high voltage, low-level current signals. Examples of these circuits include radiation monitoring and nuclear instrumentation that are subject to aging management review and subjected to adverse localized environments caused by temperature, radiation, or moisture. The program evaluates electrical insulation material for cable and connection subjected to an adverse localized environment. In addition to the evaluation and identification of adverse localized environments, either of two methods can be used to identify the existence of cable and connection insulation material aging degradation. In the first method, calibration results or findings of surveillance 

testing programs are evaluated to identify the existence of electrical cable and connection insulation material aging degradation. 

First review of calibration results or findings of surveillance test results or cable tests for license renewal completed prior to the subsequent period of extended operation 

GALL VI / SRP 3.6 
3.0-10 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

In the second method, direct testing of the cable system is performed. By reviewing the results obtained during normal calibration or surveillance, an applicant may detect severe aging degradation prior to the loss of the cable and connection intended function. The review of calibration results or findings of surveillance tests is performed at least once every 10 years. The test frequency of the cable system is determined by the applicant based on engineering evaluation, but the test frequency is at least once every 10 years. In cases where cables are not included as part of calibration or surveillance program testing circuit, a proven cable test shown to be effective in determining cable system electrical insulation condition as justified in the applicant’s aging management program is performed. The first reviews and tests are completed prior to the subsequent period of extended operation. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E3A 

Electrical Insulation for Inaccessible Medium Voltage Power Cables Not Subject To 

The program applies to inaccessible or underground (e.g., installed in buried conduits, cable trenches, cable troughs, duct banks, underground vaults, or direct buried installations) medium voltage power cable (operating voltage; 2.3kV to 35kv) within the scope of license renewal exposed to adverse localized 

First tests or first inspections for subsequent license renewal completed prior to the subsequent period 

GALL VI / SRP 3.6 
3.0-11 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

10 CFR 50.49 Environmental Qualification Requirements 

environments due primarily to significant moisture. An adverse localized environment is based on the most limiting environment (e.g., temperature, radiation, or moisture) for the cable electrical insulation. Significant moisture is considered an adverse localized environment for these in scope inaccessible cables. The cables included in this program are not subject to the environmental qualification requirements of 10 CFR 50.49. Electrical insulation subjected to an adverse localized environment could increase the rate of aging of a component and therefore have an adverse effect on operability, or potentially lead to failure of the cable’s insulation system. Although a condition monitoring program, periodic inspections are performed to prevent inaccessible cable from being exposed to significant moisture. These inspections are performed periodically based on water accumulation over time. The periodic inspection occurs at least annually with the first inspection for subsequent license renewal completed prior to the subsequent period of extended operation. Inspections are performed after event driven occurrences, such as heavy rain, thawing of ice and snow, or flooding. Both the periodic and event driven inspections include direct indication that cables are not wetted or submerged, and that cable/splices and cable support structures are intact, Dewatering systems (e.g., sump pumps and drains) and associated alarms are inspected and their operation verified. Inspections include documentation that either automatic or passive drainage 

of extended operation 
3.0-12 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

systems, or manually pumping manholes and vaults is effective in preventing inaccessible cable submergence. Test frequencies are adjusted based on test results (including trending of degradation where applicable) and plant specific operating experience. The first tests for subsequent license renewal are to be completed prior to the subsequent period of extended operation with tests performed at least every 6 years thereafter. The specific type of test performed is determined prior to the initial test, and is to be a proven test for detecting deterioration of the cable insulation system (e.g., one or more tests may be required depending to the specific cable construction: shielded and non-shielded, and the insulation material under test). Tests may include combinations of situ or laboratory; electrical, physical, or chemical testing. Testing may include inspection and testing of cable subjected to the same environment (e.g., the use of coupons – abandoned or removed cable). A plant specific inaccessible medium voltage test matrix is developed to document inspections, test methods, and acceptance criteria applicable to the applicant’s in-scope inaccessible medium voltage power cable types. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E3B 

Electrical Insulation for Inaccessible Instrument and Control Cables 

The program applies to inaccessible or underground (e.g., installed in buried conduits, cable trenches, cable troughs, duct banks, underground vaults, or direct buried installations) instrument and control cable, within the scope of license renewal exposed to adverse 

First tests or first inspections for subsequent cense renewal completed prior to the 

GALL VI / SRP 3.6 
3.0-13 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

Not Subject To 10 CFR 50.49 Environmental Qualification Requirements 

localized environments due primarily to significant moisture. An adverse localized environment is based on the most limiting environment (e.g., temperature, radiation, or moisture) for the cable electrical insulation. Significant moisture is considered an adverse localized environment for these in scope inaccessible cables. The cables included in this program are not subject to the environmental qualification requirements of 10 CFR 50.49. Electrical insulation subjected to an adverse localized environment could increase the rate of aging of a component and therefore have an adverse effect on operability, or potentially lead to failure of the cable’s insulation system. In scope inaccessible instrument and control cables submarine or other cables designed for continuous wetting or submergence are also included in this program as a onetime inspection with additional test and inspection frequencies determined by the onetime test, inspection results, and plant specific operating history. Although a condition monitoring program, periodic inspections are performed to prevent inaccessible cable from being exposed to significant moisture. These inspections are performed periodically based on water accumulation over time. The periodic inspection occurs at least annually with the first inspection for subsequent license renewal completed prior to the subsequent period of extended operation. Inspections are performed after event driven occurrences, such as heavy rain, thawing of ice and snow, or flooding. Both 

subsequent period of extended operation 
3.0-14 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

the periodic and event driven inspections include direct indication that cables are not wetted or submerged, and that cable/splices and cable support structures are intact, Dewatering systems (e.g., sump pumps and drains) and associated alarms are inspected and their operation verified. Inspections include documentation that either automatic or passive drainage systems, or manually pumping manholes and vaults is effective in preventing inaccessible cable submergence. Test frequencies are adjusted based on test results (including trending of degradation where applicable) and plant specific operating experience. The first tests for subsequent license renewal are to be completed prior to the subsequent period of extended operation with tests performed at least every 6 years thereafter. The specific type of test performed is determined prior to the initial test, and is to be a proven test for detecting deterioration of the cable insulation system (e.g., one or more tests may be required depending to the specific cable construction: shielded and non-shielded, and the insulation material under test). Tests may include combinations of situ or laboratory; electrical, physical, or chemical testing. Testing may include inspection and testing of cable subjected to the same environment (e.g., the use of coupons – abandoned or removed cable). For a large installed number of inaccessible instrumentation and control cables, a sample test methodology may be employed. A plant specific inaccessible instrument and control cables voltage test matrix is developed to document inspections, test methods, and acceptance criteria applicable to the applicant’s in-scope inaccessible instrument and control cable types. 
3.0-15 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

XI.E3C 

Electrical Insulation for Inaccessible Low Voltage Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements 

The program applies to inaccessible or underground (e.g., installed in buried conduits, cable trenches, cable troughs, duct banks, underground vaults, or direct buried installations) low 

voltage power cable (operating voltage; 1000v – but less than 2kV) within the scope of license renewal exposed to adverse localized environments due primarily to significant moisture. An adverse localized environment is based on the most limiting 

environment (e.g., temperature, radiation, or moisture) for the 

cable electrical insulation. Significant moisture is considered an adverse localized environment for these in scope inaccessible cables. The cables included in this program are not subject to the environmental qualification requirements of 10 CFR 50.49. Electrical insulation subjected to an adverse localized environment could increase the rate of aging of a component and therefore have an adverse effect on operability, or potentially lead to failure of the cable’s insulation system. Inscope inaccessible low voltage power cable splices subjected to wetting or submergence are also included within the scope of this program. In scope inaccessible low voltage submarine or other cables designed for continuous wetting or submergence are also included in this program as a onetime inspection with additional test and inspection frequencies determined by the onetime test, inspection results, and plant specific operating history. Although a condition monitoring program, periodic inspections are performed to prevent inaccessible cable from being exposed to significant moisture. These inspections are performed periodically based on water accumulation over time. The periodic inspection occurs at least annually with the first inspection for subsequent license renewal completed prior to the subsequent period of extended operation. Inspections are performed after event driven occurrences, such as heavy rain, 

First tests or first inspections for license renewal completed prior to the subsequent period of extended operation 

GALL VI / SRP 3.6 
3.0-16 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

thawing of ice and snow, or flooding. Both the periodic and event driven inspections include direct indication that cables are not wetted or submerged, and that cable/splices and cable support structures are intact, Dewatering systems (e.g., sump pumps and drains) and associated alarms are inspected and their operation verified. Inspections include documentation that either automatic or passive drainage systems, or manually pumping manholes and vaults is effective in preventing inaccessible cable submergence. Test frequencies are adjusted based on test results (including trending of degradation where applicable) and plant specific operating experience. The first tests for subsequent license renewal are to be completed prior to the subsequent period of extended operation with tests performed at least every 6 years thereafter. The specific type of test performed is determined prior to the initial test, and is to be a proven test for detecting deterioration of the cable insulation system (e.g., one or more tests may be required depending to the specific cable construction: shielded and non-shielded, and the insulation material under test). Tests may include combinations of situ or laboratory; electrical, physical, or chemical testing. Testing may include inspection and testing of cable subjected to the same environment (e.g., the use of coupons – abandoned or removed cable). For a large installed number of inaccessible low voltage power cables, a sample test methodology may be employed. A plant specific inaccessible low voltage test matrix is developed to document inspections, test methods, and acceptance criteria applicable to the applicant’s in-scope inaccessible low voltage power cable types. 

XI.E4 Metal Enclosed Bus The program requires the visual inspection of metal enclosed bus (MEB) internal surfaces to detect age- related degradation, including cracks, corrosion, foreign debris, excessive dust First inspection for subsequent license renewal completed GALL VI / SRP 3.6 
3.0-17 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

buildup, and evidence of moisture intrusion. MEB insulating material is visually inspected for signs of embrittlement, cracking, chipping, melting, swelling, discoloration, or surface contamination, which may indicate overheating or aging degradation. The internal bus insulating supports are visually inspected for structural integrity and signs of cracks. MEB external surfaces are visually inspected for loss of material due to general, pitting, and crevice corrosion. Accessible elastomers (e.g., gaskets, boots, and sealants) are inspected for degradation, including surface cracking, crazing, scuffing, and changes in dimensions (e.g., “ballooning” and “necking”), shrinkage, discoloration, hardening and loss of strength. Bolted connections are inspected for increased resistance of connection by using thermography or by measuring connection resistance using a micro-ohmmeter. When thermography is employed by the applicant, the applicant demonstrates with a documented evaluation that thermography is effective in identifying MEB increased resistance of connection (e.g., infrared viewing windows installed, or demonstrated test equipment capability). The first inspection using thermography or measuring connection resistance is completed prior to the subsequent period of extended operation and at least every 10 years thereafter. As an alternative to thermography or measuring connection resistance of accessible bolted connections covered with heat shrink tape, sleeving, insulating boots, etc., the applicant may use visual inspection of the electrical insulation to detect surface anomalies, such as embrittlement, cracking, chipping, melting, discoloration, swelling, or surface contamination. When alternative visual inspection is used to check MEB bolted connections, the first inspection is completed prior to the 

prior to the subsequent period of extended operation 
3.0-18 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

subsequent period of extended operation and every 5 years thereafter. Cable bus is a variation on MEB with similar in construction to an MEB, but instead of segregated or non-segregated electrical buses, cable bus is comprised of a fully enclosed metal enclosure that utilizes three-phase insulated power cables installed on insulated support blocks. Cable bus may omit the top cover or use a louvered top cover and enclosure. Both cable bus enclosures are not sealed against the intrusion of dust, industrial pollution, moisture, rain, or ice and therefore may be allow debris into the internal cable bus assembly. Cable bus construction and arrangement are such that it does not readily fall under a specific GALL Report AMP (e.g., GALL-SLR Report AMP XI.E4 or GALL-SLR Report AMP XI.E1). Therefore, cable bus is evaluated as a plant specific aging management program with a plant specific further evaluation. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E5 Fuse Holders 

The program was developed to specifically address aging management of fuse holder insulation material and fuse holder metallic clamp aging mechanisms and effects. In scope fuse holders located inside an active device (e.g., switchgear, power supplies, power inverters, control boards, battery chargers) and 

First tests for subsequent license renewal completed prior to the subsequent period 

GALL VI / SRP 3.6 
3.0-19 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

subject to fatigue caused by frequent fuse removal and replacement (e.g., surveillance, functional testing, and calibration) are also within the scope of this AMP. The scope of GALL-SLR Report AMP XI.E1, “Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements,” includes cable and connection electrical insulation material but not the metallic portion of cables and connections. This AMP inspects both the fuse holder electrical insulation material and the metallic portion of the fuse holder (metallic clamps). The program utilizes visual inspection and testing to identify age-related degradation for both fuse holder electrical insulation material and fuse holder metallic clamps. The specific type of test performed is determined prior to the initial test and is to be a proven test for detecting increased resistance of connection of fuse holder metallic clamps, or other appropriate testing justified in the applicant’s aging management program. Fuse holders within the scope of license renewal are visually inspected and tested at least once every 10 years to provide an indication of the condition of the fuse holder. The first visual inspections and tests for license renewal are to be completed prior to the subsequent period of extended operation. When acceptance criteria are not met, a determination is made as to whether the inspections, or tests, including frequency intervals, need to be modified. This program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated 

of extended operation 
3.0-20 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E6 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

The program provides reasonable assurance that the metallic parts of electrical cable connections that are not subject to the environmental qualification requirements of 10 CFR 50.49 and susceptible to age-related degradation resulting in increased resistance of the connection are adequately managed. External cable connections associated with in-scope cables that terminate at active or passive devices are in the scope of this AMP. Wiring connections internal to an active assembly are considered part of the active assembly and, therefore, are not within the scope of this AMP. The cable connections covered under the Environmental Qualification (EQ) program are not included in the scope of this 

program. This AMP does not include high-voltage (>35 kilovolts) switchyard connections. 

This program is a sampling program. The following factors are considered for sampling: voltage level (medium and low voltage), circuit loading (high loading), connection type, and location (high temperature, high humidity, vibration, etc.). Twenty percent of a connector type population with a maximum sample of 25 constitutes a representative connector sample size. Otherwise a technical justification of the methodology and sample size used for selecting components under test should be included as part of the applicant’s AMP documentation. The specific type of test to be performed is a proven test for detecting increased resistance of connection. 

First tests for subsequent license renewal completed prior to the subsequent period of extended operation 

GALL VI / SRP 3.6 
3.0-21 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

As an alternative to thermography or resistance measurement of cable connections for the accessible cable connections that are covered with electrical insulation materials such as tape, the applicant may perform visual inspection of the electrical insulation material to detect aging effects for covered cable connections. The basis for performing only a periodic visual inspection is documented. A representative sample of electrical connections within the scope of license renewal will be tested at least once every 10 years or at least once every 5 years if only visual inspection is used to provide an indication of the connection integrity. The first visual inspections and tests for license renewal are to be completed prior to the subsequent period of extended operation. This program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.E7 

High Voltage Insulators New AMP 

The program was developed specifically to address aging management of high voltage insulator aging mechanisms and effects. This AMP manages the age related degradation effects 

of within scope high voltage insulators susceptible to airborne contaminates including dust, salt, fog, cooling tower plume, industrial effluent or loss of material. The high voltage insulators within the scope of the subsequent period of extended operation are those credited for recovery of offsite power. 

New AMP GALL VI / SRP 3.6 
3.0-22 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

This program includes visual inspections to identify insulation and metallic component degradation. High voltage insulator surfaces are visually inspected to detect reduced insulation resistance aging effects including cracks, foreign debris, and excessive salt, dust, cooling tower plume and industrial effluent contamination. Metallic parts of the insulator are visually inspected to detect loss of material due to mechanical wear or corrosion. The high-voltage insulators within the scope of this program are to be visually inspected at least twice per year. For high voltage insulators that are coated, the visual inspection is performed at least once every 5 years. The first inspections for the subsequent period of extended operation are to be completed prior to the subsequent period of extended operation. This program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

XI.M1 

ASME Section XI Inservice Inspection, Subsections 

The program consists of periodic volumetric, surface, and/or visual examination of American Society of Mechanical Engineers (ASME) Class 1, 2, and 3 pressure-retaining components, including welds, pump casings, valve bodies, integral 

 SLR program is implemented prior to the subsequent period of extended 

GALL IV / SRP 3.1 GALL VII / SRP 3.3 
3.0-23 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

IWB, IWC, and IWD 

attachments, and pressure-retaining bolting for assessment, 

signs of degradation, and corrective actions. This program is in accordance with the ASME Code Section XI edition and addenda approved in accordance with provisions of 10 CFR 50.55a during the period of extended operation. 

operation 

XI.M2 Water Chemistry 

This program mitigates aging effects of loss of material due to corrosion, cracking due to stress corrosion cracking (SCC), and related mechanisms, and reduction of heat transfer due to fouling in components exposed to a treated water environment. Chemistry programs are used to control water chemistry for impurities (e.g., chloride, fluoride, and sulfate) that accelerate corrosion. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below the system-specific limits, based on Electric Power Research Institute (EPRI) guidelines (a) BWRVIP-190 (EPRI 

1016579, BWR Water Chemistry Guidelines – 2008 Revision) for BWRs or (b) EPRI 1014986 (PWR Primary Water Chemistry 

– Revision 6) and EPRI 1016555 (PWR Secondary Water Chemistry – Revision 7) for pressurized water reactors (PWRs). 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 

XI.M3 

Reactor Head Closure Stud Bolting 

The program includes (a) in-service inspection (ISI) in 

conformance with the requirements of the ASME Code, Section XI, Subsection IWB, Table IWB-2500-1, and (b) preventive measures to mitigate cracking. The program also relies on recommendations to address reactor head stud bolting degradation as delineated in NRC Regulatory Guide (RG) 1.65, Revision 1. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 

XI.M4 

BWR Vessel ID Attachment Welds 

The program is a condition monitoring program that manages 

cracking in the reactor vessel inside diameter attachment welds. This program relies on visual examinations to detect cracking. The examination scope, frequencies, and methods are in accordance with ASME Code, Section XI, Table-IWB-2500-1, Examination Category B-N-2, and BWRVIP48-A, “Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines,” dated November 2004. The scope of the examinations is expanded when flaws are detected. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 
3.0-24 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

Any indications are evaluated in accordance with ASME Code, 

Section XI, or the guidance in BWRVIP 48-A. Crack growth evaluations follow the guidance in BWRVIP-14-A, “Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, dated September 2008; BWRVIP-59-A, “Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV Internals,” dated May 2007; or BWRVIP-60-A, “BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy Steel RPV Internals,” dated June 2003; as appropriate. The acceptance criteria are in BWRVIP-48-A and ASME Code, Section XI, Subsubarticle IWB-3520. Repair and replacement activities are conducted in accordance with BWRVIP-52-A, “Shroud Support and Vessel Bracket Repair Design Criteria,” dated September 2005. 

XI.M5 BWR Feedwater Nozzle 

Description for plants that do not have single sleeve interference fit feedwater spargers: This program is a condition monitoring program that manages the effects of cracking in the reactor vessel feedwater nozzles. This program implements the guidance in GE-NE-523-A71-0594-A, Revision 1, “Alternate BWR Feedwater Nozzle 

Inspection Requirements,” dated May 2000. Cracking is detected through ultrasonic examinations of critical regions of the BWR feedwater nozzle, as depicted in Zones 1, 2, and 3 on [“Figure 4-1,” if the nozzle is clad, or “Figure 4-2,” if the nozzle is 

un-clad] of GE NE 523 A71-0594-A, Revision 1. The ultrasonic examination procedures, equipment, and personnel are qualified by performance demonstration in accordance with ASME Code, Section XI, Appendix VIII. The examination frequency for all 

three zones is once every 10-year ASME Code, Section XI, inservice inspection interval. Examination results are evaluated in 

accordance with ASME Code, Section XI, Subsection IWB-3130.Description for plants that have single sleeve interference fit 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 
3.0-25 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

feedwater spargers: 

This program is a condition monitoring program that manages 

the effects of cracking in the reactor vessel feedwater nozzles. This program implements the guidance in GE-NE523-A71-0594-A, Revision 1, “Alternate BWR Feedwater Nozzle Inspection Requirements,” dated May 2000. Cracking is detected through ultrasonic examinations of critical regions of the BWR feedwater nozzle, as depicted in Zones 1, 2, and 3 on [“Figure 4-1,” if the nozzle is clad, or “Figure 4-2,” if the nozzle is un-clad] of GE NE 523 A71-0594-A, Revision 1. 

The ultrasonic examination procedures, equipment, and personnel are qualified by performance demonstration in accordance with ASME Code, Section XI, Appendix VIII. The examination frequency for Zones 1 and 2 is once every [X] years, and the examination frequency for Zone 3 is once every [Y] years. Examination results are evaluated in accordance with ASME Code, Section XI, Subsection IWB-3130. 

XI.M7 

BWR Stress Corrosion Cracking 

The program manages cracking due to intergranular stress corrosion cracking (IGSCC) for all BWR piping and piping welds made of austenitic stainless steel and nickel alloy that are 4 inches or larger in nominal diameter containing reactor coolant at a temperature above 93 °C (200 °F) during power operation, regardless of code classification. The program performs volumetric examinations to detect and manage IGSCC in accordance with NRC Generic Letter (GL) 88-01. Modifications to the extent and schedule of inspection in GL 88-01 are allowed in accordance with the inspection guidance in staff-approved BWRVIP-75-A. This program relies on the staff-approved positions that are described in NUREG0313, Revision 2, and GL 88-01 and its Supplement 1 regarding selection of IGSCC-resistant materials, solution heat treatment and stress improvement processes, water chemistry, weld 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 
3.0-26 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

overlay reinforcement, partial replacement, clamping devices, crack characterization and repair criteria, inspection methods and personnel, inspection schedules, sample expansion, leakage detection, and reporting requirements. 

XI.M8 BWR Penetrations 

The program includes BWR instrumentation penetrations, control rod drive (CRD) housing and incore-monitoring housing (ICMH) penetrations, and standby liquid control nozzles/Core 

∆P 

nozzles. The program manages cracking due to cyclic loading or stress corrosion cracking by performing inspection and flaw evaluation in accordance with the guidelines of staff-approved BWRVIP-49-A, BWRVIP-47-A and BWRVIP-27-A and the requirements in the ASME Code, Section XI. The examination categories include volumetric examination methods (ultrasonic testing or radiography testing), surface examination methods (liquid penetrant testing or magnetic particle testing), and visual 

examination methods. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 

XI.M9 BWR Vessel Internals 

The program includes inspections and flaw evaluations in conformance with the guidelines of applicable staff-approved BWRVIP documents, and to ensure the long-term integrity and safe operation of BWR vessel internal components that are fabricated of nickel alloy and stainless steel (including martensitic stainless steel, cast stainless steel, and associated welds). The program manages the effects of cracking due to stress 

corrosion cracking (SCC), intergranular stress corrosion cracking (IGSCC), or irradiation-assisted stress corrosion cracking (IASCC), cracking due to cyclic loading (including flowinduced vibration), loss of material due to wear, loss of fracture 

toughness due to neutron or thermal embrittlement, and loss of preload due to thermal or irradiation-enhanced stress relaxation. The program performs inspections for cracking and loss of material in accordance with the guidelines of applicable staffapproved BWRVIP documents and the requirements of ASME Code, Section XI, Table IWB 2500-1. The impact of loss of 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 
3.0-27 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

fracture toughness on component integrity is indirectly managed by using visual or volumetric examination techniques to monitor for cracking in the components. This program also manages loss of preload for core plate rim holddown bolts and jet pump assembly holddown beam bolts by performing visual inspections or stress analyses to ensure adequate structural integrity. This program performs evaluations to determine whether supplemental inspections in addition to the existing BWRVIP examination guidelines are necessary to adequately manage loss of fracture toughness due to thermal or neutron embrittlement and cracking due to IASCC for the subsequent period of extended operation. If the evaluations determine that supplemental inspections are necessary for certain components based on neutron fluence, cracking susceptibility and fracture toughness, the program conducts the supplemental inspections for adequate aging management. 

XI.M10 Boric Acid Corrosion 

This program relies, in part, on the response to NRC Generic Letter 88-05, “Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants,” to identify, evaluate, and correct borated water leaks that could cause corrosion damage to reactor coolant pressure boundary components. The program also includes inspections, evaluations, and corrective actions for all components subject to aging management review that may be adversely affected by some form of borated water leakage. This program includes provisions to initiate evaluations and assessments when leakage is discovered by activities not associated with the program. This program follows the guidance described in Section 7 of WCAP-15988-NP, Revision 2, “Generic Guidance for an Effective Boric Inspection Program for Pressurized Water Reactors.” 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VI / SRP 3.6 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 GALL III / SRP 3.5 

 XI.M11B Cracking of Nickel-Alloy This program addresses operating experience of degradation due to primary water stress corrosion cracking (PWSCC) of SLR program is implemented prior to GALL IV / SRP 3.1 
3.0-28 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

Components and Loss of Material due to Boric AcidInduced Corrosion in Reactor Coolant Pressure Boundary Components (PWRS only) 

components or welds constructed from certain nickel alloys (e.g., Alloy 600/82/182) and exposed to pressurized water reactor primary coolant at elevated temperature. The scope of this program includes the following groups of components and materials: (a) all nickel alloy components and welds which are identified in EPRI MRP-126; (b) nickel alloy components and welds identified in ASME Code Cases N-770, N-729 and N-722, as incorporated by reference in 10 CFR 50.55a; and (c) components that are susceptible to corrosion by boric acid and may be impacted by leakage of boric acid from nearby or adjacent nickel alloy components previously described. This program is used in conjunction with GALL-SLR Report AMP XI.M2, “Water Chemistry” because water chemistry can affect the cracking of nickel alloys. The completeness of the plant’s EPRI MRP-126 program is also verified prior to entering the subsequent period of extended operation. For nickel alloy components and welds addressed by the regulatory requirements of 10 CFR 50.55a, inspections are conducted in accordance with 10 CFR 50.55a. Unless required at a greater frequency by 10 CFR 50.55a, all susceptible nickel alloy components and welds (e.g., Alloy 600/82/182 branch connection nozzles and welds) are volumetrically inspected at an interval not to exceed 10 years if such components or welds are: (a) in contact with reactor coolant; and (b) relied upon for substantial strength of the components or welds, and are of sufficient size to create a loss of coolant accident (LOCA) through a completed failure (guillotine break) or ejection of the component. Other nickel alloy components and welds within the scope of this program are inspected in accordance with EPRI MRP-126. This program also performs an inspection of bottom-mounted instrumentation (BMI) nozzles of reactor pressure vessels using a qualified volumetric examination method. The inspection is 

the subsequent period of extended operation 
3.0-29 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

conducted on all BMI nozzles prior to the subsequent period of extended operation to ensure adequate management of cracking due to PWSCC. If this inspection indicates the occurrence of PWSCC, periodic volumetric inspections are performed on these nozzles and adequate inspection periodicity is established. Alternatively, plant-proposed and staff-approved mitigation methods may be used to manage the aging effect for these components. 

XI.M12 

Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) 

The program consists of the determination of the susceptibility 

potential significance of loss of fracture toughness due to thermal aging embrittlement of CASS piping and piping components in both the BWR and PWR reactor coolant pressure boundaries emergency core cooling system (ECCS) systems, including interfacing pipe lines to the chemical and volume control system and to the spent fuel pool; and in BWR ECCS systems, including interfacing pipe lines to the suppression chamber and to the drywell and suppression chamber spray system in regard to thermal aging embrittlement based on the casting method, molybdenum content, and ferrite percentage. For potentially susceptible piping and piping components aging management is accomplished either through enhanced volumetric examination, enhanced visual examination, or a component-specific flaw tolerance evaluation. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 

XI.M17 

FlowAccelerated Corrosion (FAC) 

The program is based on the response to NRC Generic Letter 89-08, “Erosion/Corrosion-Induced Pipe Wall Thinning,” and 

relies on implementation of the Electric Power Research Institute guidelines in the Nuclear Safety Analysis Center 202L [(as applicable) Revision 2, 3, or 4], “Recommendations for an Effective Flow Accelerated Corrosion Program.” The program includes the use of predictive analytical software [(as applicable) CHECWORKS

TM, BRT CICERO

TM, COMSY]. This 

program also manages wall thinning caused by mechanisms other than FAC, in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanisms.] 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-30 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

This program includes (a) identifying all susceptible piping systems and components; (b) developing FAC predictive models to reflect component geometries, materials, and operating parameters; (c) performing analyses of FAC models and, with consideration of operating experience, selecting a sample of components for inspections; (d) inspecting components; (e) evaluating inspection data to determine the need for inspection sample expansion, repairs, or replacements, and to schedule future inspections; and (f) incorporating inspection data to refine FAC models.

XI.M18 Bolting Integrity 

This program focuses on closure bolting for pressure-retaining components and relies on recommendations for a comprehensive bolting integrity program, as delineated in NUREG-1339, and industry recommendations, as delineated in EPRI NP-5769, with the exceptions noted in NUREG-1339 for safety-related bolting. The program also relies on industry recommendations for comprehensive bolting maintenance, as delineated in the EPRI TR-104213, 1015336 and 1015337. The program generally includes periodic inspection of closure bolting for indications of loss of preload, cracking, and loss of material due to corrosion, rust, etc. The program also includes preventive measures to preclude or minimize loss of preload and cracking. A related aging management program (AMP) XI.M1, “ASME Section XI Inservice Inspection (ISI) Subsections IWB, IWC, and IWD,” includes inspections of safety-related and non-safetyrelated closure bolting and supplements this bolting integrity program. Other related programs, AMPs XI.S1, “ASME Section XI, Subsection IWE”; XI.S3, “ASME Section XI Subsection IWF”; XI.S6, “Structures Monitoring”; XI.S7, “Inspection of WaterControl Structures Associated with Nuclear Power Plant”; and 

XI.M23, “Inspection of Overhead Heavy Load and Light Load 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-31 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

(Related to Refueling) Handling Systems,” manage the inspection of safety-related and non-safety related structural bolting. 

XI.M19 Steam Generators 

This program consists of aging management activities for the steam generator tubes, plugs, sleeves, and secondary side components. This program is governed by plant technical 

specifications, commitments to NEI 97-06, Revision 3, and the associated EPRI guidelines. The program also includes foreign material exclusion as a means to inhibit wear degradation, and secondary side maintenance activities, such as sludge lancing, for removing deposits that may contribute to component degradation. The program performs volumetric examination on steam generator tubes in accordance with the requirements in the technical specifications to detect aging effects, if they should occur. The technical specifications require condition monitoring and operational assessments to be performed to ensure that the tube integrity will be maintained until the next inspection. Condition monitoring and operational assessments are done in accordance with the technical specification requirements and guidance in NEI 97-06, Revision 3. The program also includes inspections of steam generator components in accordance with the guidance in NEI 97-06, Revision 3. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 

XI.M20 

Open-Cycle Cooling Water System 

The program relies, in part, on implementing the response to NRC Generic Letter 89-13, “Service Water System Problems 

Affecting Safety-Related Equipment,” [(if applicable) and includes nonsafety-related portions of the open-cycle cooling water system]. The program includes (a) surveillance and control of biofouling, (b) tests to verify heat transfer of heat exchangers, (c) routine inspection and maintenance to ensure that corrosion, erosion, protective coating failure, fouling, and biofouling cannot degrade the performance of systems serviced by the open-cycle cooling water system. This program includes enhancements to the guidance in NRC GL 89-13 that address operating experience to ensure aging effects are adequately managed. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-32 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

XI.M21A Closed Treated Water Systems 

This is a mitigation program that also includes condition monitoring to verify the effectiveness of the mitigation activities. The program consists of (a) water treatment, including the use of 

corrosion inhibitors, to modify the chemical composition of the water such that the effects of corrosion are minimized; (b) chemical testing of the water to ensure that the water treatment program maintains the water chemistry within acceptable guidelines; and (c) inspections to determine the presence or extent of degradation. The program uses ((as applicable) e.g., EPRI 1007820, Closed Cooling Water Chemistry Guideline, and corrosion coupon testing and microbiological testing). 

Program should be implemented prior to subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 

XI.M22 Boraflex Monitoring 

The program consists of (a) neutron attenuation testing 

(“blackness testing”) to determine gap formation, (b) sampling for the presence of silica in the spent fuel pool along with boron loss, and (c) monitoring and analysis of criticality to assure that the required 5% sub-criticality margin is maintained. This program is implemented in response to NRC GL 96-04. 

SLR program is implemented prior to the subsequent period of extended operation m 

GALL VII / SRP 3.3 

XI.M23 

Inspection of Overhead Heavy Load and Light Load Handling Related to Refueling) Handling Systems 

The program evaluates the effectiveness of maintenance monitoring activities for cranes and hoists. The program includes periodic visual inspections to detect degradation of bridge, rail, and trolley structural components and loss of preload on bolted connections. Volumetric or surface examinations confirm the absence of cracking in high strength bolts. This program relies on the guidance in NUREG-0612, ASME B30.2, and other appropriate standards in the ASME B30 series. These cranes must also comply with the maintenance rule requirements provided in 10 CFR 50.65. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 

XI.M24 Compressed Air Monitoring 

The program consists of monitoring moisture content and corrosion, and performance of the compressed air system, including (a) preventive monitoring of water (moisture), and other contaminants to keep within the specified limits and (b) inspection of components for indications of loss of material due to corrosion. This program is in response to NRC GL 88-14 and INPO’s Significant Operating Experience Report (SOER) 88-01. It also relies on the guidance from the American Society of 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 
3.0-33 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

Mechanical Engineers (ASME) operations and maintenance standards and guides (ASME OM-S/G-2012, Division 2, Part 28) and American National Standards Institute (ANSI)/ISA-S7.0.1-1996, and EPRI TR-10847 for testing and monitoring air quality and moisture. Additionally, periodic visual inspections of component internal surfaces are performed for signs of loss of material due to corrosion. 

XI.M25 

BWR Reactor Water Cleanup System 

This program includes ISI and monitoring and control of reactor coolant water chemistry. Related to the inspection guidelines for the reactor water cleanup system (RWCU) inspections of RWCU piping welds that are located outboard of the second containment isolation valve, the program includes measures delineated in per the guidelines of NUREG-0313, Revision 2, and NRC GL 88-01, GL 88-01 Supplement 1, and any applicable NRC-approved alternatives to these guidelines and ISI in conformance with the ASME Section XI. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII, SRP 3.3 

XI.M26 Fire Protection 

This program includes fire barrier inspections. The fire barrier inspection program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, fire damper housings, and periodic visual inspection and functional tests of fire-rated doors to ensure that their operability is maintained. The program also includes periodic inspection and testing of halon/carbon dioxide fire suppression systems. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 

XI.M27 Fire Water System 

This program is a condition monitoring program that manages aging effects associated with water-based fire protection system components. This program manages loss of material, fouling, and flow blockage because of fouling by conducting periodic visual inspections, tests, and flushes performed in accordance with the 2011 Edition of NFPA 25. Testing or replacement of sprinklers that have been in place for 50 years is performed in accordance with NFPA 25. In addition to NFPA codes and standards, portions of the water-based fire protection system that are: (a) normally dry but periodically subjected to flow and (b) cannot be drained or allow water to collect are subjected to augmented testing beyond that specified in NFPA 25, including: 

Program is implemented 5 years before the subsequent period of extended operation. Inspections of wetted normally dry piping segments that cannot be drained or that allow water to collect begin 5 years 

GALL VII / SRP 3.3 
3.0-34 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

(a) periodic system full flow tests at the design pressure and flow rate or internal visual inspections and (b) piping volumetric wall-thickness examinations. The water-based fire protection system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions initiated. Piping wall thickness measurements are conducted when visual inspections detect surface irregularities indicative of unexpected levels of degradation. When the presence of sufficient organic or inorganic material sufficient to obstruct piping or sprinklers is detected, the material is removed and the source is detected and corrected. Non-code inspections and tests follow site procedures that include inspection parameters for items such as lighting, distance offset, presence of protective coatings, and cleaning processes that ensure an adequate examination. 

before the subsequent period of extended operation. The program’s remaining inspections begin during the subsequent period of extended operation 

XI.M29 Aboveground Metallic Tanks 

This program is a condition monitoring program that manages aging effects associated with outdoor tanks sited on soil or concrete and indoor large-volume tanks containing water designed with internal pressures approximating atmospheric pressure that are sited on concrete or soil, including the [applicant to list the specific tanks that are in the program scope]. The program includes preventive measures to mitigate corrosion by protecting the external surfaces of steel components per standard industry practice. Sealant or caulking is used for outdoor tanks at the concrete-component interface. This program manages loss of material and cracking by conducting periodic internal and external visual and surface examinations. Inspections of caulking or sealant are supplemented with physical manipulation. Surface exams are conducted to detect cracking when susceptible materials are used. Thickness measurements of tank bottoms are conducted to ensure that significant degradation is not occurring. The 

Program is implemented and inspections begin 10 years before the subsequent period of extended operation. 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-35 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

external surfaces of insulated tanks are periodically sampling-based inspected. Inspections not conducted in accordance with ASME Code Section XI requirements are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset, and surface conditions. 

XI.M30 Fuel Oil Chemistry 

This program relies on a combination of surveillance and maintenance procedures. Monitoring and controlling fuel oil contamination in accordance with the guidelines of American Society for Testing and Materials (ASTM) Standards D1796, D2276, D2709, and D4057 maintains the fuel oil quality. Exposure to fuel oil contaminants, such as water and microbiological organisms, is minimized by periodic cleaning/draining of tanks and by verifying the quality of new oil 

before its introduction into the storage tanks. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 

XI.M31 

Reactor Vessel Material Surveillance 

This program requires implementation of a reactor 

vessel material surveillance program to monitor the changes in fracture toughness to the ferritic reactor vessel beltline materials which are projected to receive a peak neutron fluence at the end of the design life of the vessel exceeding 10

17

n/cm2 (E >1MeV). The 

surveillance capsules must be located near the inside vessel wall in the beltline region so that the material specimens duplicate, to the greatest degree possible, the neutron spectrum, temperature history, and maximum neutron fluence experienced at the reactor vessel’s inner surface. Because of the resulting lead factors, surveillance capsules receive equivalent neutron fluence exposures earlier than the inner surface of the reactor vessel. This allows surveillance capsules to be withdrawn prior to the inner surface receiving an equivalent neutron fluence and therefore test results may bound the corresponding operating period in the capsule withdrawal schedule. 

The surveillance capsule withdrawal schedule revised before the subsequent period of extended operation 

Reactor Vessel Surveillance 
3.0-36 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

This surveillance program must comply with ASTM International (formerly American Society for Testing and Materials) Standard Practice E 185-82, as incorporated by reference in 10 CFR Part 50, Appendix H. Because the withdrawal schedule in Table 1 of ASTM E 185-82 is based on plant operation during the original 40-year license term, standby capsules may need to be incorporated into the Appendix H program to ensure appropriate monitoring during the subsequent period of extended operation. Surveillance capsules are designed and located to permit insertion of replacement capsules. If standby capsules will be incorporated into the Appendix H program for the subsequent period of extended operation and have been removed from the reactor vessel, these should be reinserted so that appropriate lead factors are maintained and test results will bound the corresponding operating period. This program includes removal and testing of at least one capsule during the subsequent period of extended operation, with a neutron fluence of the capsule between one and one and one quarter (1.25) the projected peak vessel neutron fluence at the end of the subsequent period of extended operation. As an alternative to a plant-specific surveillance program complying with ASTM E 185-82, an integrated surveillance program (ISP) may be considered for a set of reactors that have similar design and operating 

features, in accordance with 10 CFR Part 50, 

Appendix H, and Paragraph III.C. The plant-specific 

implementation of the ISP is consistent with the latest version of the ISP plan that has received approval by the NRC for the subsequent period of extended operation. 
3.0-37 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

The objective of this Reactor Vessel Material Surveillance program is to provide sufficient material data and dosimetry to (a) monitor irradiation embrittlement to neutron fluences greater than the projected neutron fluence at the end of the subsequent period of extended operation, and (b) provide adequate dosimetry monitoring during the operational period. If surveillance capsules are not withdrawn during the subsequent period of extended operation, provisions are made to perform dosimetry monitoring. This program is a condition monitoring program that measures the increase in Charpy V-notch 30 foot-pound (ft-lb) transition temperature and the drop in the uppershelf energy as a function of neutron fluence and irradiation temperature. The data from this surveillance program are used to monitor neutron irradiation 

embrittlement of the reactor vessel, and are inputs to the neutron embrittlement time-limited aging analyses (TLAAs) described in Section 4.2 of the Standard Review Plan for Subsequent License Renewal (SRPSLR). The Reactor Vessel Material Surveillance program is also used in conjunction with GALL-SLR Report AMP X.M2, “Neutron Fluence Monitoring,” which monitors neutron fluence for reactor vessel components and reactor vessel internal components. In accordance with 10 CFR Part 50, Appendix H, all surveillance capsules, including those previously removed from the reactor vessel, must meet the test procedures and reporting requirements of ASTM E 185-82, to the extent practicable, for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including the conversion of standby capsules into the Appendix H program and extension of 
3.0-38 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

the surveillance program for the subsequent period of extended operation, must be approved by the Nuclear Regulatory Commission (NRC) prior to implementation, in accordance with 10 CFR Part 50, Appendix H, Paragraph III.B.3. Standby capsules placed in storage (e.g., removed from the reactor vessel) are maintained for possible future insertion. 

XI.M32 One-Time Inspection 

The program is a condition monitoring program consisting of a one-time inspection of selected components to verify: (a) the system-wide effectiveness of an AMP that is designed to prevent or minimize aging to the extent that it will not cause the loss of intended function during the subsequent period of extended operation; (b) the insignificance of an aging effect; and (c) that long-term loss of materials will not cause a loss of intended function for steel components exposed to environments that do not include corrosion inhibitors as a preventive action, and where periodic wall thickness measurements on a representative sample of each environment are not conducted every 5 years up to at least 10 years prior to the subsequent period of extended operation. This program provides inspections that verify that unacceptable degradation is not occurring. It also may trigger additional actions that ensure the intended functions of affected components are maintained during the subsequent period of extended operation. The elements of the program include (a) determination of the sample size of components to be inspected based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (b) identification of the inspection locations in the system or component based on the potential for the aging effect to occur, (c) determination of the 

examination technique, including acceptance criteria that would 

Inspections should be conducted prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-39 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

be effective in managing the aging effect for which the component is examined, and (d) an evaluation of the need for follow-up examinations to monitor the progression of aging if age-related degradation is found that could jeopardize an intended function before the end of the subsequent period of extended operation. This program is not used for structures or components with known age-related degradation mechanisms or when the environment in the subsequent period of extended operation is not expected to be equivalent to that in the prior operating periods. Periodic inspections are conducted in these cases. Inspections not conducted in accordance with ASME Code Section XI requirements are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset, and surface conditions. 

XI.M33 Selective Leaching 

This program is a condition monitoring program that includes a one-time inspection for components exposed to a closed-cycle cooling water or treated water environment when plant-specific operating experience has not revealed selective leaching in 

these environments. Opportunistic and periodic inspections are conducted for raw water, waste water, soil, and groundwater environments, and for closed-cycle cooling water and treated water environments when plant-specific operating experience 

has revealed selective leaching in these environments. Visual inspections coupled with mechanical examination techniques such as chipping or scraping are conducted. Periodic destructive examinations of components for physical properties (i.e., degree of dealloying, depth of dealloying, through wall thickness, and chemical composition) are conducted for components exposed to raw water, waste water, soil, and groundwater environments, or for closed-cycle cooling water and treated water environments when plant-specific operating experience has revealed selective leaching in these environments. Inspections and tests are conducted to 

SLR program should be implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-40 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

determine whether loss of material will affect the ability of the components to perform their intended function for the subsequent period of extended operation. Inspections are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset and surface conditions. When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the subsequent period of extended operation, additional inspections are performed. 

XI.M35 

ASME Code Class 1 Small Bore-Piping 

This program augments the existing ASME Code, Section XI requirements and is applicable to small-bore ASME Code Class 1 piping and systems with a nominal pipe size diameter less than 4 inches (NPS<4) and greater than or equal to NPS 1. This program provides a one-time volumetric inspection of a sample of this Class 1 piping. This program includes pipes, fittings, branch connections, and all full and partial penetration (socket) welds. The program includes measures to verify that degradation is not occurring, thereby either confirming that there 

is no need to manage aging-related degradation or validating the effectiveness of any existing program for the subsequent period of extended operation. The one-time inspection program for ASME Code Class 1 small-bore piping includes locations that are susceptible to cracking. This program is applicable to systems that have not experienced cracking of ASME Code Class 1 small-bore piping. This program can also be used for systems that experienced cracking but have implemented design changes to effectively mitigate cracking. (Measure of effectiveness includes (1) the one-time inspection sampling is statistically significant; (2) samples will be selected as described in Element 5; and (3) no repeated failures over an extended period of time.) For systems that have experienced cracking and operating experience indicates design changes have not been implemented to effectively mitigate cracking, periodic inspection is proposed, as managed by a plant-specific AMP. Should evidence of cracking be revealed by a one-time 

SLR program should be implemented prior to subsequent period of extended operation 

GALL IV / SRP 3.1 
3.0-41 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

inspection, a periodic inspection is also proposed, as managed by a plant-specific AMP. 

XI.M36 

External Surfaces Monitoring of Mechanical Components 

This program is a condition monitoring program that manages loss of material, cracking, changes in material properties (of cementitious components), hardening and loss of strength (of elastomeric components), and reduced thermal insulation resistance. Periodic visual inspections, not to exceed a refueling outage interval, of metallic, polymeric, insulation jacketing (insulation when not jacketed), and cementitious components are conducted. For certain materials, such as flexible polymers, physical manipulation or pressurization to detect hardening or loss of strength is used to augment the visual examinations conducted under this program. A sample of outdoor component surfaces that are insulated and a sample of indoor insulated components exposed to condensation (due to the in-scope component being operated below the dew point), are periodically inspected every 10 years during the subsequent period of extended operation. Inspections not conducted in accordance with ASME Code Section XI requirements are conducted in accordance with 

plant-specific procedures including inspection parameters such as lighting, distance, offset, and surface conditions. Acceptance criteria are such that the component will meet its intended 

function until the next inspection or the end of the subsequent 

period of extended operation. Qualitative acceptance criteria are clear enough to reasonably ensure a singular decision is derived based on observed conditions. 

Program is implemented 6 months before the subsequent period of extended operation and inspections begin during the subsequent period of extended operation. 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 

XI.M37 Flux Thimble Tube Inspection 

The program inspects for the thinning of flux thimble tube walls, which provides a path for the in-core neutron flux monitoring 

system detectors and forms part of the reactor coolant system pressure boundary. Flux thimble tubes are subject to loss of material at certain locations in the reactor vessel where flowinduced fretting causes wear at discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly 

SLR program is implemented prior to the subsequent period of extended operation 

GALL IV / SRP 3.1 
3.0-42 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

instrument guide tube. A periodic nondestructive examination methodology, such as eddy current testing or other applicantjustified and US NRC-accepted inspection methods is used to monitor flux thimble tube wear. This program implements the recommendations of NRC Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors.” 

XI.M38 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

This program is a condition monitoring program that manages loss of material, cracking, and hardening and loss of strength of polymeric materials. This program consists of visual inspections of all accessible internal surfaces of metallic piping, piping components, ducting, heat exchanger components, polymeric and elastomeric components, and other components that are exposed to environments of uncontrolled indoor air, outdoor air, air with borated water leakage, condensation, moist air, diesel exhaust, and any water environment other than open-cycle cooling water, closed-cycle cooling water, and fire water. 

Elastomers exposed to open-cycle, closed-cycle cooling water, and fire water are managed by this program. These internal inspections are performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. At a minimum, in each 10-year period during the period of extended operation a representative 

sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population is inspected. Where practical, the inspections focus on the bounding or lead components most susceptible to aging because of time in service, and severity of operating conditions. Opportunistic inspections continue in each period despite meeting the sampling limit. For certain materials, such as flexible polymers, physical manipulation or pressurization to detect hardening or loss of strength is used to augment the visual examinations conducted under this program. If visual 

Program is implemented 6 months before the subsequent period of extended operation and inspections begin during the subsequent period of extended operation. 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 GALL VI / SRP 3.6 
3.0-43 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

inspection of internal surfaces is not possible, a plant-specific program is used. Inspections not conducted in accordance with ASME Code Section XI requirements are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset, and surface conditions. Acceptance criteria are such that the component will meet its intended function until the next inspection or the end of the subsequent period of extended operation. Qualitative acceptance criteria are clear enough to reasonably ensure a singular decision is derived based on observed conditions. 

XI.M39 Lubricating Oil Analysis 

This program ensures that the oil environment in the mechanical systems is maintained to the required quality. This program ensures that oil systems are maintained free of contaminants (primarily water and particulates), thereby preserving an environment that is not conducive to loss of material or reduction of heat transfer. Testing activities include sampling and analysis of lubricating oil for detrimental contaminants. The presence of 

water or particulates may also indicate in-leakage and corrosion product buildup. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 

XI.M40 

Monitoring of NeutronAbsorbing Materials other than Boraflex 

This program relies on periodic inspection, testing, monitoring, and analysis of the criticality design to assure that the required 5 percent sub-criticality margin is maintained. This program consists of inspecting the physical condition of the neutronabsorbing material, such as visual appearance, dimensional measurements, weight, geometric changes (e.g., formation of blisters, pits, and bulges), and boron areal density as observed from coupons or in situ. 

SLR program should be implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 

XI.M41 

Buried and Underground Piping and Tanks 

This program is a condition monitoring program that manages the aging effects associated with the external surfaces of buried 

and underground piping and tanks such as loss of material, cracking and changes in material properties (for cementitious piping). It addresses piping and tanks composed of any material, including metallic, polymeric, and cementitious 

SLR program should be implemented before the subsequent period of extended operation 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-44 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

materials. The program also manages aging through preventive and mitigative actions, (i.e., coatings, backfill quality, and cathodic protection) The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. Where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, actual loss of material rates are measured from in-situ coupons. Inspections are conducted by qualified individuals. Adverse inspection results result in additional inspections. If a reduction in the number of inspections recommended in GALL-SLR Report AMP XI.M41, Table XI.M41-1, is claimed based on a lack of soil corrosivity as determined by soil testing, soil testing is conducted once in each 10-year period starting 10 years prior to the subsequent period of extended operation.

XI.M42 

Internal Coatings/Linings for In Scope Piping, Piping Components, Heat Exchangers, and Tanks 

This program is a condition monitoring program that manages degradation of coatings/linings that can lead to loss of material of base materials and downstream effects such as reduction in flow, reduction in pressure or reduction in heat transfer when coatings/linings become debris. This program manages these aging effects by conducting periodic visual inspections of all coatings/linings applied to the internal surfaces of in-scope components exposed to closed-cycle cooling water, raw water, treated water, treated borated water, waste water, lubricating oil or fuel oil where loss 

of coating or lining integrity could impact the component’s or downstream component’s current licensing basis intended function(s). For tanks and heat exchangers, all accessible surfaces are inspected. Piping inspections are sampling-based. The training and qualification of individuals involved in coating/lining inspections of noncementitious coatings/linings are 

Program is implemented no later than six months before the subsequent period of extended operation and inspections begin no later than the last refueling outage before the subsequent period of extended operation. 

GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 
3.0-45 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

conducted in accordance with ASTM International Standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces. Peeling and delamination is not acceptable. Blisters are evaluated by a coatings specialist with the blisters being surrounded by sound material and with the size and frequency not increasing. Minor cracks in cementitious coatings are acceptable provided there is no evidence of debonding. All other degraded conditions are evaluated by a coatings specialist. For coated/lined surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair or replacement of the coating/lining. 

XI.S1 

ASME Section XI, Subsection IWE Inservice Inspection (IWE) 

This program is in accordance with ASME Section XI, Subsection IWE, consistent with 10 CFR 50.55a “Codes and standards,” with supplemental recommendations. The AMP includes periodic visual, surface, volumetric examinations, and leak rate testing, where applicable, of metallic pressure-retaining components of steel containments and concrete containments for signs of degradation, damage, irregularities including liner plate bulges, and for coated areas distress of the underlying 

metal shell or liner, and corrective actions. Acceptability of inaccessible areas of steel containment shell or concrete containment steel liner is evaluated when conditions found in accessible areas, indicate the presence of, or could result in, flaws or degradation in inaccessible areas. This program also includes aging management for the potential loss of material due to corrosion in the inaccessible areas of the BWR Mark I steel containment, and surface examination for the detection of cracking of structural bolting. In addition, the program includes supplemental surface or enhanced examinations to detect cracking for specific components [identify components], and supplemental volumetric examinations by sampling locations 

SLR program is implemented prior to the subsequent period of extended operation 

 GALL II / SRP 3.5 
3.0-46 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

susceptible to loss of thickness due to corrosion of containment shell or liner that is inaccessible from one side. Inspection results are compared with prior recorded results in acceptance of components for continued service. 

XI.S2 

ASME Section XI, Subsection IWL Inservice Inspection (IWL) 

This program consists of (a) periodic visual inspection of concrete surfaces for reinforced and pre-stressed concrete containments, (b) periodic visual inspection and sample tendon testing of un-bonded post-tensioning systems for pre-stressed concrete containments for signs of degradation, assessment of damage, and corrective actions, and testing of the tendon corrosion protection medium and free water. Measured tendon lift-off forces are compared to predicted tendon forces calculated 

in accordance with RG 1.35. The Subsection IWL requirements are supplemented to include quantitative acceptance criteria for concrete surfaces based on the "Evaluation Criteria" provided in Chapter 5 of ACI 349.3R 

SLR program is implemented prior to the subsequent period of extended operation 

GALL II / SRP 3.5 

XI.S3 

ASME Section XI, Subsection IWF Inservice inspection (IWF) 

This program consists of periodic visual examination of piping and component supports for signs of degradation, evaluation, and corrective actions. This program recommends additional inspections beyond the inspections required by the 10 CFR Part 50.55a ASME Section XI, Subsection IWF program. This includes inspections of an additional 5 percent of supports outside of the existing IWF sample population. For high-strength bolting in sizes greater than 1 inch nominal diameter, volumetric examination comparable to that of ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1 should be performed to detect cracking in addition to the VT-3 examination. If a component support does not exceed the acceptance standards of IWF-3400 but is electively repaired to as-new condition, the sample is increased or modified to include another support that is representative of the remaining population of supports that were not repaired. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL II / SRP 3.5 GALL III / SRP 3.5 
3.0-47 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

XI.S4 10 CFR Part 50, Appendix J 

This program consists of monitoring leakage rates through the containment system, its shell or liner, associated welds, penetrations, isolation valves, fittings, and other access openings to detect degradation of the containment pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria. This program is implemented in accordance with 10 CFR Part 50 Appendix J, RG 1.163 and/or NEI 94-01. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL II / SRP 3.5 

XI.S5 Masonry Walls 

This program consists of inspections, based on IE Bulletin 80-11 and plant-specific monitoring proposed by IN 87-67, for managing shrinkage, separation, gaps, loss of material and cracking of masonry walls such that the evaluation basis is not invalidated and intended functions are maintained. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL III / SRP 3.5 

XI.S6 Structures Monitoring 

This program consists of periodic visual inspection and monitoring the condition of concrete and steel structures, structural components, component supports, and structural commodities to ensure that aging degradation (such as those described in ACI 349.3R, ACI 201.1R, SEI/ASCE 11, and other documents) will be detected, the extent of degradation determined, evaluated, and corrective actions taken prior to loss of intended functions. Inspections also include seismic joint fillers, elastomeric materials; and steel edge supports and steel bracings associated with masonry walls, and periodic evaluation of groundwater chemistry and opportunistic inspections for the condition of below grade concrete, and of protective coatings for substrate materials. Quantitative results (measurements) and qualitative data from periodic inspections are trended with photographs and surveys for the type, severity, extent, and 

progression of degradation. The acceptance criteria are derived from applicable consensus codes and standards. For concrete structures, the program includes personnel qualifications and quantitative acceptance criteria of ACI 349.3R. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL VII / SRP 3.3 GALL II / SRP 3.5 GALL III / SRP 3.5 GALL VI / SRP 3.6 

XI.S7 

Inspection of Water-Control Structures 

This program consists of inspection and surveillance of rawwater control structures associated with emergency cooling systems or flood protection. The program also includes 

SLR program is implemented prior to the subsequent 

GALL III / SRP 3.5 
3.0-48 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

Associated with Nuclear Power Plants 

structural steel and structural bolting associated with watercontrol structures. In general, parameters monitored should be in accordance with Section C.2 of R.G. 1.127 and quantitative measurements should be recorded for all applicable parameters monitored or inspected. Inspections should occur at least once every 5 years. Structures exposed to aggressive water require additional plant-specific investigation. 

period of extended operation 

XI.S8 

Protective Coating Monitoring and Maintenance 

This program ensures that a monitoring and maintenance program implemented in accordance with RG 1.54 is adequate for the subsequent period of extended operation. The program consists of guidance for selection, application, inspection, and maintenance of protective coatings. Maintenance of Service Level I coatings applied to carbon steel and concrete surfaces inside containment (e.g., steel liner, steel containment shell, structural steel, supports, penetrations, and concrete walls and 

floors) serve to prevent or minimize loss of material due to corrosion of carbon steel components and aids in decontamination. Degraded coatings in the containment are assessed periodically to ensure post-accident operability of the ECCS. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL III / SRP 3.5 

X.M1 Cyclic Load Monitoring 

The aging management program monitors and tracks the number of occurrences and severity of each of the thermal and pressure transients and requires corrective actions to ensure that applicable fatigue analyses remain within their allowable limits, including those in applicable CUF analyses, CUFen analyses, maximum allowable stress range reduction analyses for ANSI B31.1 and ASME Code Class 2 and 3 components, ASME III fatigue waiver analyses, and cycle-based flaw growth, flaw tolerance, or fracture mechanics analyses. The program manages cracking induced by fatigue or cyclic loading occurrences in plant structures and components by monitoring one or more relevant fatigue parameters, which include the CUF, the CUFen, transient cycle limits, and the predicted flaw size. The program has two aspects, one to verify the continued acceptability of existing analyses through cycle counting and the 
3.0-49 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

other to provide periodically updated evaluations of the fatigue analyses to demonstrate that they continue to meet the appropriate limits. Plant technical specification requirements may apply to these activities. 

X.M2 Neutron Fluence Monitoring 

This program monitors and tracks increasing neutron fluence exposures (integrated, time-dependent neutron flux exposures) to reactor pressure vessel and reactor internal components to ensure that applicable reactor pressure vessel neutron irradiation embrittlement analyses (i.e., TLAAs) and radiationinduced aging effect assessment for reactor internal components will remain within their applicable limits. This program has two aspects, one to verify the continued acceptability of existing analyses through neutron fluence monitoring and the other to provide periodically updated evaluations of the analyses involving neutron fluence inputs to demonstrate that they continue to meet the appropriate limits defined in the current licensing basis (CLB). Monitoring is performed in accordance with neutron flux determination methods and neutron fluence projection methods that are defined for the CLB in NRC-approved reports. For fluence monitoring activities that apply to components located in the beltline region of the reactor pressure vessel(s), the monitoring methods are performed in a manner that is consistent with the monitoring methodology guidelines in Regulatory Guide (RG) 1.190, “Calculational .and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,” March 2001. Additional justifications may be necessary for neutron fluence monitoring methods that are applied to reactor pressure vessel component locations outside of the beltline region of the vessels or to reactor internal components. This program’s results are compared to the neutron fluence parameter inputs used in the neutron embrittlement analyses for reactor pressure vessel components. This includes but is not 
3.0-50 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

limited to the neutron fluence inputs for the reactor pressure vessel upper shelf energy analyses (or equivalent margin analyses, as applicable to the CLB), pressure-temperature analyses, and low temperature overpressure protection (LTOP, PWRs only) that are required to be performed in accordance in 10 CFR Part 50, Appendix G requirements, and for PWRs, those safety analyses that are performed to demonstrate adequate protection of the reactor pressure vessels against the consequences of pressurized thermal shock (PTS) events, as required by 10 CFR 50.61 or 10 CFR 50.61a and applicable to the CLB. Comparisons to the neutron fluence inputs for other analyses (as applicable to the CLB) may include those for mean RTNDT and probability of failure analyses for BWR reactor 

pressure vessel circumferential and axial shell welds, BWR core reflood design analyses, and aging effect assessments for PWR and BWR reactor internals that are induced by neutron irradiation exposure mechanisms. Reactor vessel surveillance capsule dosimetry data obtained in accordance with 10 CFR Part 50, Appendix H requirements and 

through implementation of the applicant’s Reactor Vessel Surveillance Program (Refer to GALL-SLR Report AMP XI.M31) may provide inputs to and have impacts on the neutron fluence monitoring results that are tracked by this program. In addition, regulatory requirements in the plant technical specifications or in specific regulations of 10 CFR Part 50 may apply, including those in 10 CFR Part 50, Appendix G; 10 CFR 50.55a; and for PWRs, the PTS requirements in 10 CFR 50.61 or 10 CFR 50.61a, as applicable for the CLB. 

X.S1 

Concrete Containment Tendon Prestress 

The prestressing unbonded tendons are used to impart compressive forces in the prestressed concrete containments to 

resist the internal pressure inside the containment that would be generated in the event of a LOCA. The prestressing forces generated by the unbonded tendons diminish over time due to losses in prestressing forces in the tendons and in the 
3.0-51 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

surrounding concrete. The prestressing force analysis and evaluation has been completed and determined to remain within allowable limits to the end of the subsequent period of extended operation, and the trend lines of the measured prestressing forces will stay above the minimum required prestressing forces for each group of tendons to the end of this period. 

X.E1 

Environmental Qualification (EQ) of Electric Components 

This program implements the environmental qualification (EQ) 

requirements in 10 CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49. 10 CFR 50.49 specifically requires that an EQ program be established to demonstrate that certain electrical equipment located in harsh plant environments will perform their safety function in those harsh environments after the effects of in-service aging. 10 CFR 50.49 requires that the effects of significant aging mechanisms be addressed as part of environmental qualification. As required by 10 CFR 50.49, EQ equipment not qualified for the current license term is refurbished, replaced, or have their qualification extended prior to reaching the designated life aging limits established in the evaluation. Aging evaluations for EQ equipment that specify a qualification of at least 60 years are time-limited aging analyses (TLAAs) for subsequent license renewal. Reanalysis of an aging evaluation to extend the qualification of equipment qualified under the program requirements of 10 CFR 50.49(e) is performed as part of an EQ program. Important attributes for the reanalysis of an aging evaluation include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). The analytical models used in the reanalysis of an aging evaluation are the 

same as those previously applied during the prior evaluation. The identification of excess conservatism in electrical equipment service conditions (for example, temperature, radiation, and 
3.0-52 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

cycles) used in the prior aging evaluation is the chief method used for a reanalysis. A reanalysis demonstrates that adequate margin is maintained consistent with the original analysis in accordance with 10 CFR 50.59 requiring certain margins and accounting for the unquantified uncertainties established in the EQ aging evaluation of the equipment. Reanalysis of an aging evaluation is used to extend the environmental qualification of the component. If the qualification cannot be extended by reanalysis, the equipment is refurbished, replaced, or requalified prior to exceeding the current qualified life. When the reanalysis assessed margins, conservatisms, or assumptions do not support reanalysis (e.g., extending qualified life) of an EQ component, the use of on-going qualification techniques including condition monitoring or condition based methodologies may be implemented. Ongoing qualification is an alternative means to provide reasonable assurance that an equipment environmental qualification is maintained for the subsequent period of extended operation. On-going qualification of electric equipment important to safety subject to the requirements of 10 CFR 50.49 involves the inspection, observation, measurement, or trending of one or more indicators, which can be correlated to the condition or functional performance of the EQ equipment. This program is implemented in accordance 10 CFR 50.49 and 10 CFR 54.21(c)(1)(iii). Along with GALL-SLR Report AMP X.E1 the environmental qualification program demonstrates the acceptability of the TLAA analysis under 10 CFR 54.21(c)(1) and is considered an aging management programs (AMP) for the subsequent period of extended operation. This program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience including research and 
3.0-53 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

development (e.g., test methods, aging models, acceptance criterion) such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report. [The FSAR Summary description also includes a plant specific discussion of applicable commitments, license conditions, enhancements, or exceptions applied to the applicants aging management program] 

SRP-SLR Appendix A 

Plant-Specific AMP 

The [fill in name of program] Program is a [prevention, 

mitigation, condition monitoring, performance monitoring] program that manages aging effects associated with [list component type or system as applicable that are in the scope of the program]. Preventive or mitigative actions include [fill in key actions when applicable]. The program manages [list the AERM] by conducting [periodic, one-time] [describe inspection methods and tests] of [all components or a representative sample of components] within the scope of the program. [When applicable, Periodic inspections are conducted every XX years commencing prior to or during the subsequent period of extended operation] [Describe how inspection and test implementing procedures are controlled (e.g., non-code inspections and tests follow site procedures that include inspection parameters for items such as lighting, distance offset, presence of protective coatings, and cleaning processes that ensure an adequate examination)]. Qualitative acceptance criteria are clear enough to reasonably ensure a singular decision is derived based on observed conditions. When the 

acceptance criteria are not met such that it is determined that 

the affected component should be replaced prior to the end of the subsequent period of extended operation, additional inspections are performed. 

Program should be implemented prior to subsequent period of extended operation 

GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 GALL II-III / SRP 3.5 GALL VI / SRP 3.6 

GALL-SLR Appendix A 

Quality Assurance 

The 10 CFR Part 50, Appendix B quality assurance program provides the basis for corrective actions, the confirmation process, and administrative controls for AMPs for license 

SLR program is implemented prior to the subsequent 

GALL VII / SRP 3.3 GALL VIII / SRP 3.4 GALL III / SRP 3.5 
3.0-54 

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

AMP 

GALL-SLR 

Program Description of Program 

Implementation 

Schedule*

Applicable GALLSLR Report and 

SRP-SLR Chapter 

References 

renewal. The scope of this existing program is expanded to include non-safety-related structures and components that are subject to aging management programs. 

period of extended operation 

GALL VI / SRP 3.6 

GALL-SLR Appendix B 

Operating Experience 

This program captures the operating experience from plantspecific and industry sources and is systematically reviewed on 

an ongoing basis in accordance with the quality assurance program, which meets the requirements of 10 CFR Part 50, Appendix B, and the operating experience program, which meets the requirements of NUREG-0737, “Clarification of TMI Action Plan Requirements,” Item I.C.5, “Procedures for Feedback of Operating Experience to Plant Staff.” This program interfaces with and relies on active participation in the Institute of Nuclear Power Operations’ (INPO) operating experience program, as endorsed by the NRC. In accordance with these programs, all incoming operating experience items are screened to determine whether they may involve age-related degradation or aging management impacts. Items so identified are further evaluated and the AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined through these evaluations that the effects of aging may not be adequately managed. Training on age-related degradation and aging management is provided to those personnel responsible for implementing the AMPs and who may submit, screen, assign, evaluate, or otherwise process plant-specific and 

industry operating experience. Plant-specific operating experience associated with aging management and age-related degradation is reported to the industry in accordance with guidelines established in the operating experience program. 

SLR program is implemented prior to the subsequent period of extended operation 

GALL II-III / SRP 3.5 GALL IV / SRP 3.1 GALL V / SRP 3.2 GALL VI / SRP 3.6 GALL VII / SRP 3.3 GALL VIII / SRP 3.4 

*An applicant need not incorporate the implementation schedule into its FSAR. However, the reviewer should verify that the applicant has identified and committed in the license renewal application to any future aging management activities to be completed before the subsequent period of extended operation. The 

staff expects to impose a license condition on any renewed license to ensure that the applicant will complete these activities no later than the committed date. 
3.1-1 

1 3.1 Aging Management Of Reactor Vessel, Internals, And Reactor 

2 Coolant System 

3 Review Responsibilities 

4 Primary—The Branch’s assigned responsibility by Project Manager (PM) as described in this 

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

6 Power Plants (SRP-SLR) Section 3.0. 

7 3.1.1 Areas of Review 

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

9 management program (AMP) of the reactor vessel, internals, and reactor coolant system. For a 

10 recent vintage plant, the information related to the reactor vessel, internals, and reactor coolant 

11 system is contained in Chapter 5, “Reactor Coolant System and Connected Systems,” of the 

12 plant’s final safety analysis report (FSAR), consistent with the “Standard Review plan (SRP) for 

13 the Review of Safety Analysis Reports for Nuclear Power Plants” (NUREG–0800). For older 

14 plants, the location of applicable information is plant-specific because an older plant’s FSAR 

15 may have predated NUREG–0800. 

16 The reactor vessel, internals, and reactor coolant system includes the reactor vessel and 

17 internals. For boiling water reactors (BWRs), this system also includes the reactor coolant 

18 recirculation system and portions of other systems connected to the pressure vessel extending 

19 to the first isolation valve outside of containment or to the first anchor point. These connected 

20 systems include residual heat removal, low-pressure core spray, high-pressure core spray, 

21 low-pressure coolant injection, high-pressure coolant injection, reactor core isolation cooling, 

22 isolation condenser, reactor coolant cleanup, feedwater, and main steam. For pressurized 

23 water reactors (PWRs), the reactor coolant system includes the primary coolant loop, the 

24 pressurizer, and the steam generators (SGs). For PWRs the reactor coolant system also 

25 includes the pressurizer relief tank, which is not an American Society of Mechanical Engineers 

26 (ASME) Code Class 1 component. The connected systems for PWRs include the residual heat 

27 removal or low pressure injection system, core flood spray or safety injection tank, chemical and 

28 volume control system or high-pressure injection system, and sampling system. 

29 The responsible review organization is to review the following subsequent license renewal 

30 application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 3.0: 

31 AMRs 

32  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

33 License Renewal (GALL-SLR) Report 

34  AMR results for which further evaluation is recommended 

35  AMR results not consistent with or not addressed in the GALL-SLR Report 

36 AMPs 

37 Consistent with GALL-SLR Report AMPs (including those with enhancements 

38 and/or exceptions) 
3.1-2 

1  Plant-specific AMPs

2 FSAR Supplement 

3  The responsible review organization is to review the FSAR Supplement associated with 

4 each assigned AMP. 

5 3.1.2 Acceptance Criteria 

6 The acceptance criteria for the areas of review describe methods for determining whether the 

7 applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

8 regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

9 3.1.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

10 Learned for Subsequent License Renewal Report 

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

12 are described and evaluated in Chapter IV of the GALL-SLR Report. 

13 The applicant’s SLRA should provide sufficient information so that the reviewer is able to 

14 confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

15 cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item 

16 is consistent with the GALL-SLR Report AMR item to which it is compared. When the 

17 applicant is crediting a different AMP than recommended in the GALL-SLR Report, the 

18 reviewer should confirm that the alternate AMP is valid to use for aging management and will be 

19 capable of managing the effects of aging as adequately as the AMP recommended by the 

20 GALL-SLR Report. 

21 3.1.2.2 Aging Management Review Results for Which Further Evaluation Is 

22 Recommended by the Generic Aging Lessons Learned for Subsequent License 

23 Renewal Report 

24 The basic acceptance criteria defined in Subsection 3.1.2.1 need to be applied first for all of the 

25 AMRs and AMPs reviewed as part of this section. In addition, if further evaluation is 

26 recommended, then additional criteria apply for each of the following aging effect/aging 

27 mechanism combinations. Refer to Table 3.1-1, comparing the “Further Evaluation 

28 Recommended” and the “GALL-SLR” column, for the AMR items that reference the 

29 following subsections. 

30 3.1.2.2.1 Cumulative Fatigue Damage 

31 The evaluations of fatigue or cyclical loading stresses may be time-limited aging analyses 

32 (TLAAs), as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

33 10 CFR 54.21(c)(1). These types of TLAAs are addressed separately in Section 4.3, “Metal 

34 Fatigue Analysis,” of this SRP-SLR. 

35 3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

36 1. Loss of material due to general, pitting, and crevice corrosion could occur in the steel 

37 PWR SG upper and lower shell and transition cone exposed to secondary feedwater and 

38 steam. The existing program relies on control of water chemistry to mitigate corrosion 
3.1-3 

1 and inservice inspection (ISI) to detect loss of material. The extent and schedule of the 

2 existing SG inspections are designed to ensure that flaws cannot attain a depth sufficient 

3 to threaten the integrity of the welds. However, according to NRC Information Notice 

4 (IN) 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam 

5 Generators,” the program may not be sufficient to detect pitting and crevice corrosion if 

6 general and pitting corrosion of the shell is known to exist. Augmented inspection is 

7 recommended to manage this aging effect. Furthermore, this issue is limited to 

8 Westinghouse Model 44 and 51 Steam Generators, where a high-stress region exists at 

9 the shell to transition cone weld. Acceptance criteria are described in Branch Technical 

10 Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

11 2. Loss of material due to general, pitting, and crevice corrosion could occur in the steel 

12 PWR steam generator shell assembly exposed to secondary feedwater and steam. The 

13 existing program relies on control of secondary water chemistry to mitigate corrosion. 

14 However, some applicants have replaced only the bottom part of their recirculating SGs, 

15 generating a cut in the middle of the transition cone, and, consequently, a new transition 

16 cone closure weld. It is recommended that volumetric examinations be performed in 

17 accordance with the requirements of ASME Code Section XI for upper shell and lower 

18 shell-to-transition cones with gross structural discontinuities for managing loss of 

19 material due to general, pitting, and crevice corrosion in the welds for Westinghouse 

20 Model 44 and 51 Steam Generators, where a high-stress region exists at the 

21 shell-to-transition cone weld. 

22 The new continuous circumferential weld, resulting from cutting the transition cone as 

23 discussed above, is a different situation from the SG transition cone welds containing 

24 geometric discontinuities. Control of water chemistry does not preclude loss of material 

25 due to pitting and crevice corrosion at locations of stagnant flow conditions. The new 

26 transition area weld is a field weld as opposed to having been made in a controlled 

27 manufacturing facility, and the surface conditions of the transition weld may result in flow 

28 conditions more conducive to initiation of general, pitting, and crevice corrosion than 

29 those of the upper and lower transition cone welds. Crediting of the ISI program for the 

30 new SG transition cone weld may not be an effective basis for managing loss of material 

31 in this weld, as the ISI criteria would only perform a VT-2 visual leakage examination of 

32 the weld as part of the system leakage test performed pursuant to ASME Section XI 

33 requirements. In addition, ASME Section XI does not require licensees to remove 

34 insulation when performing visual examination on nonborated treated water systems. 

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

36 ensure that loss of material due to general, pitting and crevice corrosion is not occurring. 

37 For the new continuous circumferential weld, further evaluation is recommended to verify 

38 the effectiveness of the chemistry control program. A one-time inspection at susceptible 

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

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

41 function will be maintained during the subsequent period of extended operation. 

42 Furthermore, this issue is limited to replacement of recirculating SGs with a new 

43 transition cone closure weld. 

44 3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

45 1. Neutron irradiation embrittlement is a TLAA to be evaluated for the subsequent period of 

46 extended operation for all ferritic materials that have a neutron fluence greater than 
3.1-4 

1017 n/cm2 1 [E >1 MeV] at the end of the subsequent period of extended operation. 

2 Certain aspects of neutron irradiation embrittlement are TLAAs as defined in 

3 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

4 10 CFR 54.21(c)(1). This TLAA is addressed separately in Section 4.2, “Reactor Vessel 

5 Neutron Embrittlement Analysis,” of this SRP-SLR Report. 

6 2. Loss of fracture toughness due to neutron irradiation embrittlement could occur in BWR 

7 and PWR reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and 

8 neutron flux. A reactor vessel material surveillance program monitors neutron irradiation 

9 embrittlement of the reactor vessel. The reactor vessel material surveillance program is 

10 plant-specific, depending on matters such as the composition of limiting materials and 

11 the availability of surveillance capsules. 

12 In accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its 

13 proposed withdrawal schedule for approval prior to implementation. Untested capsules 

14 placed in storage must be maintained for future insertion. Thus, further NRC staff 

15 evaluation is required for SLR. Specific recommendations for an acceptable AMP are 

16 provided in GALL-SLR Report AMP XI.M31, “Reactor Vessel Material Surveillance.” 

17 A neutron fluence monitoring program is used to monitor the neutron fluence levels that 

18 are used as the time-dependent inputs for the plant’s reactor vessel neutron irradiation 

19 embrittlement TLAAs. These TLAAs are the subjects of the topics discussed in 

20 SRP-SLR Section 3.1.2.2.3.1 and “acceptance criteria” and “review procedure” 

21 guidance in SRP-SLR Section 4.2. Specific recommendations for an acceptable 

22 neutron fluence monitoring AMP are provided in GALL-SLR Report AMP X.M2, 

23 “Neutron Fluence Monitoring.” 

24 3. Reduction in Fracture Toughness is a plant-specific TLAA for Babcock & Wilcox (B&W) 

25 reactor internals to be evaluated for the subsequent period of extended operation in 

26 accordance with the NRC staff’s safety evaluation concerning “Demonstration of the 

27 Management of Aging Effects for the Reactor Vessel Internals,” B&W Owners Group 

28 report number BAW-2248, which is included in BAW-2248A, March 2000. Plant-specific 

29 TLAAs are addressed in Section 4.7, “Other Plant-Specific Time-Limited Aging 

30 Analyses,” of this SRP-SLR. 

31 3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

32 Corrosion Cracking 

33 1. Cracking due to stress corrosion cracking (SCC) and intergranular stress corrosion 

34 cracking (IGSCC) could occur in the stainless steel (SS) and nickel alloy BWR top head 

35 enclosure vessel flange leak detection lines. The Generic Aging Lessons Learned for 

36 Subsequent License Renewal (GALL-SLR) Report recommends that a plant-specific 

37 AMP be evaluated because existing programs may not be capable of mitigating or 

38 detecting cracking due to SCC and IGSCC. Acceptance criteria are described in Branch 

39 Technical Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

40 2. Cracking due to SCC and IGSCC could occur in SS BWR isolation condenser 

41 components exposed to reactor coolant. The existing program relies on control of 

42 reactor water chemistry to mitigate SCC and on ASME Section XI ISI to detect cracking. 

43 However, the existing program should be augmented to detect cracking due to SCC and 

44 IGSCC. An augmented program is recommended to include temperature and 
3.1-5 

1 radioactivity monitoring of the shell-side water and eddy current testing of tubes to 

2 ensure that the component’s intended function will be maintained during the subsequent 

3 period of extended operation. Acceptance criteria are described in BTP RLSB-1 

4 (Appendix A.1 of this SRP-SLR Report). 

5 3.1.2.2.5 Crack Growth Due to Cyclic Loading 

6 Crack growth due to cyclic loading could occur in reactor vessel shell forgings clad with SS 

7 using a high-heat-input welding process. Growth of intergranular separations (underclad 

8 cracks) in the heat-affected zone under austenitic SS cladding is a TLAA to be evaluated for the 

9 subsequent period of extended operation for all the SA-508-Cl-2 forgings where the cladding 

10 was deposited with a high-heat-input welding process. The methodology for evaluating the 

11 underclad flaw should be consistent with the flaw evaluation procedure and criterion in the 

ASME Section XI Code2 12 . 

13 See SRP-SLR, Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses,” for generic 

14 guidance for meeting the requirements of 10 CFR 54.21(c). 

15 3.1.2.2.6 Cracking Due to Stress Corrosion Cracking 

16 1. Cracking due to SCC could occur in the PWR SS reactor vessel flange leak detection 

17 lines and bottom-mounted instrument guide tubes exposed to reactor coolant. Further 

18 evaluation is recommended to ensure that these aging effects are adequately managed. 

19 A plant-specific AMP should be evaluated to ensure that this aging effect is adequately 

20 managed. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP21 SLR Report). 

22 2. Cracking due to SCC could occur in Class 1 PWR cast austenitic stainless steel (CASS) 

23 reactor coolant system piping and piping components exposed to reactor coolant. The 

24 existing program relies on control of water chemistry to mitigate SCC; however, SCC 

25 could occur for CASS components that do not meet the NUREG–0313, “Technical 

26 Report on Material Selection and Process Guidelines for BWR Coolant Pressure 

27 Boundary Piping” guidelines with regard to ferrite and carbon content. Further 

28 evaluation is recommended of a plant-specific program for these components to ensure 

29 that this aging effect is adequately managed. Acceptance criteria are described in 

30 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

31 3.1.2.2.7 Cracking Due to Cyclic Loading 

32 Cracking due to cyclic loading could occur in steel and SS BWR isolation condenser 

33 components exposed to reactor coolant. The existing program relies on ASME Section XI ISI. 

34 However, the existing program should be augmented to detect cracking due to cyclic loading. 

35 An augmented program is recommended to include temperature and radioactivity monitoring of 

36 the shell-side water and eddy current testing of tubes to ensure that the component’s intended 

 

2

Refer to the GALL-SLR Report, Chapter I, for applicability of other editions of the ASME Code, Section XI. 
3.1-6 

1 function will be maintained during the subsequent period of extended operation. Acceptance 

2 criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

3 3.1.2.2.8 Loss of Material Due to Erosion 

4 Loss of material due to erosion could occur in steel steam generator feedwater impingement 

5 plates and supports exposed to secondary feedwater. Further evaluation is recommended of a 

6 plant-specific AMP to ensure that this aging effect is adequately managed. Acceptance criteria 

7 are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

8 3.1.2.2.9 Aging Management of Pressurized Water Reactor Vessel Internals (Applicable to 

9 Subsequent License Renewal Periods Only) 

10 Electric Power Research Institute (EPRI) Topical Report (TR) No. 1022863, “Materials 

11 Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

12 (MRP-227-A)” [henceforth TR Materials Reliability Program (MRP)-227-A, which may be 

13 accessed at ADAMS Accession Nos. ML12017A191 through ML12017A197 and 

14 ML12017A199], provides the industry’s current aging management recommendations for the 

15 reactor vessel internal (RVI) components that are included in the design of a PWR facility. In 

16 this report, the EPRI MRP identified that the following aging mechanisms may be applicable to 

17 the design of the RVI components in these types of facilities: (a) SCC, (b) irradiation-assisted 

18 stress corrosion cracking (IASCC), (c) fatigue, (d) wear, (e) neutron irradiation embrittlement, 

19 (f) thermal aging embrittlement, (g) void swelling and irradiation growth, or (h) thermal or 

20 irradiation-enhanced stress relaxation or irradiation enhanced creep. The methodology in 

21 TR MRP-227-A was approved by the NRC in a safety evaluation dated December 16, 2011 

22 (ML11308A770), which includes those plant-specific applicant/licensee action items that a 

23 licensee or applicant applying the MRP-227-A report would need to address and resolve and 

24 apply to its licensing basis. 

25 The EPRI MRP’s functionality analysis and failure modes, effects, and criticality analysis 

26 (FMECA) bases for grouping Westinghouse-designed, B&W-designed and Combustion 

27 Engineering (CE)-designed RVI components into these inspection categories was based on an 

28 assessment of aging effects and relevant time-dependent aging parameters through a 

29 cumulative 60-year licensing period (i.e., 40 years for the initial operating license period plus an 

30 additional 20 years during the initial period of extended operation). The EPRI MRP has yet to 

31 assess whether potential operations of Westinghouse-designed, B&W-designed and 

32 CE-designed reactors during a SLR period would have any impact on the existing susceptibility 

33 rankings and inspection categorizations for the RVI components in these designs, as defined in 

34 TR MRP-227-A or its applicable MRP background documents (e.g., TR MRP-191 for 

35 Westinghouse-designed or CE-designed RVI components or MRP-189 for B&W-designed 

36 components). 

37 Therefore, for PWR facilities’ SLRAs, a plant-specific AMP for the RVI components will be 

38 needed to demonstrate that the RVI components will be managed in accordance with the 

39 requirements of 10 CFR 54.21(a)(3) during the proposed SLR period. Components for 

40 inspection, parameters monitored, monitoring methods, inspection sample size, frequencies, 

41 expansion criteria, and acceptance criteria are to be justified in the SLRA. The NRC staff will 

42 assess the adequacy of the plant-specific AMP against the criteria for the 10 AMP program 

43 elements that are defined in Sections A.1.2.3.1 through A.1.2.3.10 of SRP-SLR Appendix A.1.
3.1-7 

1 3.1.2.2.10 Loss of Material Due to Wear 

2 1. Industry operating experience indicates that loss of material due to wear can 

3 occur in PWR control rod drive (CRD) head penetration nozzles made of nickel 

4 alloy due to the interactions between the nozzle and the thermal sleeve 

5 centering pads of the nozzle (see Ref. 31). The CRD head penetration nozzles 

6 are also called control rod drive mechanism (CRDM) nozzles or CRDM head 

7 adapter tubes. The applicant should perform a further evaluation to confirm the 

8 adequacy of a plant-specific AMP or analysis (with any necessary inspections) 

9 for management of the aging effect. The applicant may use the acceptance 

10 criteria, which are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR 

11 Report), to demonstrate the adequacy of a plant-specific AMP. Alternatively, the 

12 applicant may perform an analysis with any necessary inspections to confirm 

13 that loss of material due to wear does not affect the intended function(s) of these 

14 CRD head penetration nozzles, consistent with the current licensing basis (CLB). 

15 2. Industry operating experience indicates that loss of material due to wear can occur in the 

16 SS thermal sleeves of PWR CRD head penetration nozzles due to the interactions 

17 between the nozzle and the thermal sleeve (e.g., where the thermal sleeve exits from 

18 the head penetration nozzle inside the reactor vessel as described in Ref. 32). 

19 Therefore, the applicant should perform a further evaluation to confirm the adequacy of a 

20 plant-specific AMP for management of the aging effect. The applicant may use the 

21 acceptance criteria, which are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR 

22 Report), to demonstrate the adequacy of a plant-specific AMP.

23 3.1.2.2.11 Cracking Due to Primary Water Stress Corrosion Cracking 

24 1. Foreign operating experience in steam generators with a similar design to that of 

25 Westinghouse Model 51 has identified cracking due to primary water stress corrosion 

26 cracking (PWSCC) in SG divider plate assemblies fabricated of Alloy 600 and/or the 

27 associated Alloy 600 weld materials, even with proper primary water chemistry 

28 (EPRI TR-1014982). Cracks have been detected in the stub runner, adjacent to the 

29 tubesheet/stub runner weld. Therefore, the water chemistry program may not be 

30 effective in managing the aging effect of cracking due to PWSCC in SG divider plate 

31 assemblies. This is of particular concern for SGs where the tube-to-tubesheet welds are 

32 considered structural welds and/or where the divider plate assembly contributes to the 

33 mechanical integrity of the tube-to-tube sheet welds. 

34 Although these SG divider plate cracks may not have a significant safety impact in and 

35 of themselves, these cracks could impact adjacent items, such as the tube-to-tubesheet 

36 welds and the channel head, if they propagate to the boundary with these items. For the 

37 tube-to-tubesheet welds, PWSCC cracks in the divider plate could propagate to the 

38 tubesheet cladding with possible consequences to the integrity of the tube-to-tubesheet 

39 welds. For the channel head, the PWSCC cracks in the divider plate could propagate to 

40 the SG triple point and potentially affect the pressure boundary of the SG channel head. 

41 The existing program may rely on control of reactor water chemistry to mitigate cracking 

42 due to PWSCC. A plant-specific AMP should be evaluated, along with the primary water 

43 chemistry program, because the existing primary water chemistry program may not be 

44 capable of mitigating cracking due to PWSCC. Acceptance criteria are described in 

45 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 
3.1-8 

1 2. Cracking due to PWSCC could occur in SG nickel alloy tube-to-tubesheet welds 

2 exposed to reactor coolant. Unless the NRC has approved a redefinition of the pressure 

3 boundary in which the tube-to-tubesheet weld is no longer included, the effectiveness 

4 of the primary water chemistry program should be verified to ensure cracking is 

5 not occurring: 

6  For plants with Alloy 600 SG tubes that have not been thermally treated and for 

7 which an alternate repair criteria such as C*, F*, or W* has been permanently 

8 approved, the weld is no longer part of the pressure boundary and no plant 

9 specific AMP is required; 

10  For plants with Alloy 600 steam generator tubes that have not been thermally 

11 treated and for which there is no permanently approved alternate repair criteria 

12 such as C*, F*, or W*, a plant-specific AMP is required; 

13  For plants with Alloy 600TT SG tubes and for which an alternate repair criteria 

14 such as H* has been permanently approved, the weld is no longer part of the 

15 pressure boundary and no plant specific AMP is required; 

16  For plants with Alloy 600TT SG tubes and for which no alternate repair criteria 

17 such as H* permanently approved, a plant-specific AMP is required; 

18  For plants with Alloy 690TT SG tubes with Alloy 690 tubesheet cladding, the 

19 water chemistry is sufficient, and no further action or plant-specific AMP 

20 is required; 

21  For plants with Alloy 690TT SG tubes and with Alloy 600 tubesheet cladding, 

22 either a plant-specific program or a rationale for why such a program is not 

23 needed is required. 

24 The existing program relies on control of reactor water chemistry to mitigate cracking 

25 due to PWSCC. A plant-specific AMP should be evaluated, along with the primary water 

26 chemistry program, because the existing primary water chemistry program may not be 

27 capable of mitigating cracking due to PWSCC. Acceptance criteria are described in 

28 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

29 3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking 

30 1. GALL-SLR Report AMP XI.M9, “BWR Vessel Internals,” manages aging 

31 degradation of nickel alloy and SS, including associated welds, which are used 

32 in BWR vessel internal components. When exposed to the BWR vessel 

33 environment, these materials can experience cracking due to IASCC. The 

34 existing Boiling Water Reactor Vessel and Internals Project (BWRVIP) 

35 examination guidelines are mainly based on aging evaluation of BWR vessel 

36 internals for operation up to 60 years. However, increases in neutron fluence 

37 during the SLR term may need to be assessed for supplemental inspections of 

38 BWR vessel internals to adequately manage cracking due to IASCC. Therefore, 

39 the applicant should perform an evaluation to determine whether supplemental 

40 inspections are necessary in addition to those recommended in the existing 

41 BWRVIP examination guidelines. If the applicant determines that supplemental 

42 inspections are not necessary, the applicant should provide adequate technical 
3.1-9 

1 justification for the determination. If supplemental inspections are determined 

2 necessary for BWR vessel internals, the applicant identifies the components to 

3 be inspected and performs supplemental inspections to adequately manage 

4 IASCC. In addition, the applicant should confirm the adequacy of any necessary 

5 supplemental inspections and enhancements to the BWRVIP. 

6 2. The GALL-SLR Report recommends AMP XI.M1, “ASME Section XI Inservice 

7 Inspection, Subsections IWB, IWC, and IWD” for managing IASCC for the core 

8 shroud support plate access hole cover (welded or mechanical). GALL-SLR 

9 Report AMP XI.M1 manages the aging effect by performing visual examinations. 

10 The GALL-SLR AMP also performs augmented inspections using ultrasonic 

11 testing (UT) or other demonstrated acceptable techniques if the welded access 

12 hole cover has a crevice which is not amenable to visual examinations. 

13 Cracking due to IASCC in this component can be facilitated by the increases in 

14 neutron fluence during the subsequent period of extended operation. Therefore, 

15 an evaluation should be performed to determine whether supplemental 

16 inspections are necessary for adequate aging management in addition to the 

17 existing ASME Code examination as augmented for crevices. The applicant 

18 should also confirm the adequacy of any necessary supplemental inspections 

19 and enhancements to the ASME Section XI ISI, Subsections IWB, IWC, and 

20 IWD program. 

21 3.1.2.2.13 Loss of Fracture Toughness Due to Neutron Irradiation or Thermal 

22 Aging Embrittlement 

23 GALL-SLR Report AMP XI.M9 manages aging degradation of nickel alloy and SS, 

24 including associated welds, which are used in BWR vessel internal components. When 

25 exposed to the BWR vessel environment, these materials can experience loss of 

26 fracture toughness due to neutron irradiation embrittlement. In addition, CASS, 

27 precipitation-hardened (PH) martensitic SS (e.g., 15-5 and 17-4 PH steel) and 

28 martensitic SS (e.g., 403, 410, 431 steel) can experience loss of fracture toughness due 

29 to neutron irradiation and thermal aging embrittlement. 

30 The existing BWRVIP examination guidelines are mainly based on aging evaluation of BWR 

31 vessel internals for operation up to 60 years. Increases in neutron fluence and thermal 

32 embrittlement during the SLR term may need to be assessed for supplemental inspections of 

33 BWR vessel internals to adequately manage loss of fracture toughness due to neutron 

34 irradiation or thermal aging embrittlement. Therefore, the applicant should perform an 

35 evaluation to determine whether supplemental inspections are necessary in addition to those 

36 recommended in the existing BWRVIP examination guidelines. If the applicant determines that 

37 supplemental inspections are not necessary, the applicant should provide adequate technical 

38 justification for the determination. If supplemental inspections are determined necessary for 

39 BWR vessel internals, the applicant should identify the components to be inspected and perform 

40 supplemental inspections to adequately manage loss of fracture toughness. In addition, the 

41 applicant should confirm the adequacy of any necessary supplemental inspections and 

42 enhancements to the BWRVIP. 

43 3.1.2.2.14 Loss of Preload Due to Thermal or Irradiation-Enhanced Stress Relaxation 

44 GALL-SLR Report AMP XI.M9 manages loss of preload due to thermal or irradiation-enhanced 

45 stress relaxation in BWR core plate rim holddown bolts. The issue is applicable to 
3.1-10 

1 BWR-designed light water reactors that employ rim holddown bolts as the means for protecting 

2 the reactor’s core plate from the consequences of lateral movement. The potential for such 

3 movement, if left unmanaged, could impact the ability of the reactor to be brought to a safe 

4 shutdown condition during an anticipated transient occurrence or during a postulated 

5 design-basis accident or seismic event. This issue is not applicable to BWR reactor designs 

6 that use wedges as the means of precluding lateral movement of the core plate because 

7 the wedges are fixed in place and are not subject to this type of aging effect and 

8 mechanism combination. 

9 GALL-SLR Report AMP XI.M9 states that the inspections in BWRVIP TR No. BWRVIP-25, 

10 “BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines 

11 (BWRVIP-25),” are used to manage loss of preload due to thermal or irradiation-enhanced 

12 stress relaxation in BWR designs with core plate rim holddown bolts. However, in previous 

13 LRAs, some applicants have identified that the inspection bases for managing loss of preload in 

14 TR No. BWRVIP-25 may not be capable of gaining access to the rim holddown bolts or are not 

15 sufficient to detect loss of preload on the components. For applicants that have identified this 

16 issue in their past LRAs, the applicants either committed to modifying the plant design to install 

17 wedges in the core plate designs or to submit an inspection plan, with a supporting core plate 

18 rim holddown bolt preload analysis for NRC approval at least 2 years prior to entering into the 

19 initial period of extended operation for the facility. 

20 For SLRAs that apply to BWRs with core plate rim holddown bolts, the NRC staff recommends 

21 that an enhanced augmented inspection basis for the bolts be proposed and justified, with a 

22 supporting loss of preload analysis. If an existing NRC-approved analysis for the bolts exists in 

23 the CLB and conforms to the definition of a TLAA, the applicant should identify the analysis as a 

24 TLAA for the LRA and demonstrate how the analysis is acceptable in accordance with either 

25 10 CFR 54.21(c)(1)(i), (ii), or (iii). Otherwise, if a new analysis will be performed to support an 

26 updated augmented inspection basis for the bolts for the subsequent period of extended 

27 operation, the NRC staff recommends that a license renewal commitment be placed in the 

28 FSAR supplement for the applicant to submit both the inspection plan and the supporting loss of 

29 preload analysis to the NRC staff for approval at least 2 years prior to entering into the 

30 subsequent period of extended operation for the facility. 

31 3.1.2.2.15 Loss of Material Due to Boric Acid Corrosion 

32 Foreign operating experience identified loss of material due to boric acid corrosion in the steel 

33 base material of a recirculating SG channel head. This corrosion primarily occurs when the 

34 plant is shutdown and the steam generators are exposed to oxygen. The observed loss of 

35 material was volumetric in the form of one large cavity. The loss of material was associated 

36 with an area where the channel head cladding did not fully cover the steel base material. The 

37 cause of the missing cladding is not currently known. This operating experience indicates that if 

38 SG head cladding is compromised (e.g., due to cracking, manufacturing defects or foreign 

39 material impingement damage), loss of material due to boric acid corrosion could occur in the 

40 steel base material of the SG head (i.e., recirculating steam generator channel head and 

41 once-through SG upper and lower heads). 

42 The existing program may rely on control of reactor water chemistry to mitigate loss of material 

43 due to boric acid corrosion for SG head base material when the cladding of this component was 

44 compromised and the steel base material was exposed to reactor coolant. A plant-specific AMP 

45 should be evaluated, along with the Water Chemistry program, to ensure that the program is 
3.1-11 

1 capable of managing loss of material due to boric acid corrosion for the SG head base material. 

2 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

3 3.1.2.2.16 Cracking Due to Cyclic Loading 

4 1. Cracking due to cyclic loading could occur in BWR steel and SS welded connections 

5 between the re-routed control rod drive return line and the inlet piping system that 

6 delivers return line flow to the reactor pressure vessel, which are exposed to reactor 

7 coolant. Further evaluations of condition monitoring activities are recommended to 

8 ensure that cracking is detected before there is a loss of intended function. Periodic 

9 inspections in accordance with the recommendations in NUREG–0619, Section 8.2, are 

10 acceptable for the detection of cracking. Specifically, the welded connection that joins 

11 the re-routed control rod drive return line to the inlet piping system that returns flow to 

12 the reactor vessel should be inspected during each refueling outage. This inspection 

13 should use UT and include base metal to a distance of one-pipe-wall thickness or 

14 0.5 inches, whichever is greater, on both sides of the weld. The inlet piping into which 

15 the control rod drive return line flow is connected should also be inspected by UT to a 

16 distance of at least one pipe diameter downstream of the welded connection. For other 

17 approaches, acceptance criteria are described in Appendix A.1 of this SRP-SLR Report. 

18 No condition monitoring activities are necessary if the control rod drive return line 

19 was removed. 

20 2. Cracking due to cyclic loading could occur in BWR-2 steel (with or without SS cladding) 

21 CRD return line nozzles and their nozzle-to-vessel welds exposed to reactor coolant. 

22 Further evaluation of a plant-specific AMP is recommended to ensure that this aging 

23 effect is adequately managed because BWR-2 designs do not have a cut and capped 

24 CRD return line nozzle and thus may be more susceptible to cracking. Acceptance 

25 criteria are described in Appendix A.1 of this SRP-SLR. 

26 3.1.2.2.17 Cracking Due to Stress Corrosion Cracking or Intergranular Stress 

27 Corrosion Cracking 

28 Cracking due to SCC and IGSCC could occur in BWR SS and nickel alloy piping, and piping 

29 components greater than or equal to 4 inches nominal pipe size (NPS); nozzle safe ends and 

30 associated welds; and CRD return line nozzle caps and the associated cap-to-nozzle welds or 

31 cap-to-safe end welds in BWR-3, BWR-4, BWR-5, and BWR-6 designs that are exposed to 

32 reactor coolant. GALL-SLR Report AMP XI.M2, “Water Chemistry,” is recommended to mitigate 

33 SCC and IGSCC, and augmented inspection activities are recommended in accordance with 

34 GALL-SLR Report AMP XI.M7, “BWR Stress Corrosion Cracking,” for condition monitoring. 

35 However, these programs may need to be augmented to manage the effects of cracking in 

36 dead-legs and other piping locations with stagnant flow where localized environmental 

37 conditions could exacerbate the mechanisms of SCC and IGSCC. Further evaluation is 

38 recommended to identify any such locations and to evaluate the adequacy of the applicant’s 

39 proposed AMPs on a case-by-case basis to ensure that the intended functions of components in 

40 these locations will be maintained during the subsequent period of extended operation. 

41 Acceptance criteria are described in Appendix A.1 of this SRP-SLR. 
3.1-12 

1 3.1.2.2.18 Loss of Material Due to General, Crevice or Pitting Corrosion and 

2 Microbiologically-Induced Corrosion and Cracking Due to Stress 

3 Corrosion Cracking 

4 Loss of material due to general (steel only), crevice, or pitting corrosion and 

5 microbiologically-induced corrosion and cracking due to SCC (SS only) can occur in steel and 

6 SS piping and piping components exposed to concrete. Concrete provides a high alkalinity 

7 environment that can mitigate the effects of loss of material for steel piping, thereby significantly 

8 reducing the corrosion rate. However, if water intrudes through the concrete, the pH can be 

9 reduced and ions that promote loss of material such as chlorides, which can penetrate the 

10 protective oxide layer created in the high alkalinity environment, can reach the surface of the 

11 metal. Carbonation can reduce the pH within concrete. The rate of carbonation is reduced by 

12 using concrete with a low water-to-cement ratio and low permeability. Concrete with low 

13 permeability also reduces the potential for the penetration of water. Adequate air entrainment 

14 improves the ability of the concrete to resist freezing and thawing cycles and therefore reduces 

15 the potential for cracking and intrusion of water. Intrusion of water can also bring bacteria to the 

16 surface of the metal, potentially resulting in microbiologically-induced corrosion in steel or SS. 

17 Cracking due to SCC, as well as pitting and crevice corrosion can occur due to halides present 

18 in the water that penetrates to the surface of the metal. 

19 If the following conditions are met, loss of material is not considered to be an applicable aging 

20 effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

21 (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air 

22 entrainment) as cited in NUREG–1557; (b) plant-specific operating experience indicates no 

23 degradation of the concrete that could lead to penetration of water to the metal surface; and 

24 (c) the piping is not potentially exposed to ground water. For SS components loss of material 

25 and cracking due to SCC are not considered to be applicable aging effects as long as the piping 

26 is not potentially exposed to groundwater. Where these conditions are not met, loss of material 

27 due to general (steel only), crevice or pitting corrosion and microbiologically-induced corrosion 

28 and cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

29 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

30 these aging effects. 

31 3.1.2.2.19 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically32 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

33 Water, or Sodium Pentaborate Solution 

34 Loss of material due to crevice corrosion can occur in steel with SS cladding, SS, and nickel 

35 alloy piping, piping components, heat exchanger components, spent fuel storage racks, tanks, 

36 and PWR heat exchanger components exposed to treated water, treated borated water, or 

37 sodium pentaborate solution if oxygen levels are greater than 100 ppb. In addition, loss of 

38 material due to pitting can occur if oxygen levels are greater than 100 ppb, halides or sulfates 

39 levels are greater than 150 ppb, and stagnant flow conditions exist. Loss of material due to 

40 microbiologically-induced corrosion can occur with steel with SS cladding, SS, and nickel alloy 

41 piping, piping components, heat exchanger components, spent fuel storage racks, tanks, and 

42 PWR heat exchanger components exposed to treated water, treated borated water, or sodium 

43 pentaborate solution if the pH is less than 10.5 and temperature is less than 99 °C [210 °F]. 

44 Where oxygen levels are less than or equal to 100 ppb, GALL-SLR Report AMP XI.M2, “Water 

45 Chemistry,” and GALL-SLR Report AMP XI.M32, “One-Time Inspection,” are acceptable 

46 methods to manage loss of material due to pitting and crevice corrosion. Where oxygen levels 
3.1-13 

1 are greater than 100 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR 

2 Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

3 Components,” are acceptable methods to manage loss of material due to crevice corrosion. 

4 Where stagnant flow conditions exist, and oxygen levels are greater than 100 ppb and halides 

5 or sulfates levels are greater than 150 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” 

6 and GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

7 and Ducting Components,” are acceptable methods to manage loss of material due to pitting 

8 and crevice corrosion. 

9 Where the pH is greater than or equal to 10.5 and the temperature is greater than or equal to 

10 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR Report 

11 AMP XI.M32, “One-Time Inspection,” are acceptable methods to manage loss of material due to 

12 loss of material due to microbiologically-induced corrosion. Where the pH is less than 10.5 and 

13 temperature is less than 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and 

14 GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

15 Ducting Components,” are acceptable methods to manage loss of material due to 

16 microbiologically-induced corrosion. 

17 3.1.2.2.20 Quality Assurance for Aging Management of Nonsafety-Related Components 

18 Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR Report). 

19 3.1.2.2.21 Ongoing Review of Operating Experience 

20 Acceptance criteria are described in Appendix A.4, “Operating Experience for AMPs.” 

21 3.1.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

22 Generic Aging Lessons Learned for Subsequent License Renewal Report 

23 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

24 3.1.2.4 Aging Management Programs 

25 For those AMPs that will be used for aging management and are based on the program 

26 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

27 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

28 GALL-SLR Report, Chapters X, “Aging Management Programs That May Be Used to 

29 Demonstrate Acceptability of Time-Limited Aging Analyses in Accordance With Under 

30 10 CFR 54.21(c) (1)(iii)” and XI, “Aging Management Programs.” 

31 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

32 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

33 10 CFR 54.21(a)(3) would still be met. The reviewer should then confirm that the SLRA AMP 

34 with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the SLRA 

35 AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR Report 

36 AMP that should have been identified as an exception to the GALL-SLR Report AMP, the 

37 difference should be reviewed and properly dispositioned. The reviewer should document the 

38 disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

39 The SLRA should identify any enhancements that are needed to permit an existing licensee 

40 AMP to be declared consistent with the GALL-SLR Report AMP to which the licensee AMP is 
3.1-14 

1 compared. The reviewer is to confirm both that the enhancement, when implemented, would 

2 allow the existing licensee AMP to be consistent with the GALL-SLR Report AMP and that the 

3 applicant has a commitment in the FSAR Supplement to implement the enhancement prior to 

4 the subsequent period of extended operation. The reviewer should document the disposition of 

5 all enhancements. 

6 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

7 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

8 (Appendix A.1.2.3 of this SRP-SLR Report). 

9 3.1.2.5 Final Safety Analysis Report Supplement 

10 The programs and activities for managing the effects of aging for the subsequent period of 

11 extended operation described in the FSAR Supplement should be sufficiently comprehensive, 

12 such that later changes can be controlled by 10 CFR 50.59. The description should contain 

13 information associated with the bases for determining that aging effects will be managed during 

14 the subsequent period of extended operation. The description should also contain any future 

15 aging management activities, including enhancements and commitments, to be completed 

16 before the subsequent period of extended operation. Table 3.0-1 of this SRP-SLR provides 

17 examples of the type of information to be included in the FSAR Supplement. Table 3.1-2 lists 

18 the programs that are applicable for this SRP-SLR subsection. 

19 3.1.3 Review Procedures 

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

21 3.1.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

22 Learned for Subsequent License Renewal Report 

23 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

24 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

25 approved in the GALL-SLR Report. The reviewer should not conduct a re-review of the 

26 substance of the matters described in the GALL-SLR Report. If the applicant has provided the 

27 information necessary to adopt the finding of program acceptability as described and evaluated 

28 in the GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to the 

29 GALL-SLR Report in its SLRA. In making this determination, the reviewer confirms that the 

30 applicant has provided a brief description of the system, components, materials, and 

31 environment. The reviewer also confirms that the applicable aging effects have been addressed 

32 based on the staff’s review of industry and plant-specific operating experience. 

33 Furthermore, the reviewer should confirm that the applicant has addressed operating 

34 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

35 requires the reviewer to confirm that the applicant has identified those aging effects for the 

36 reactor vessel, internals, and reactor coolant system components that are contained in the 

37 GALL-SLR Report as applicable to its plant. 
3.1-15 

1 3.1.3.2 Aging Management Review Results for Which Further Evaluation Is 

2 Recommended by the Generic Aging Lessons Learned for Subsequent License 

3 Renewal Report 

4 The basic review procedures defined in Subsection 3.1.3.1 need to be applied first for all of the 

5 AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to 

6 which the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

7 additional criteria apply for each of the following aging effect/aging mechanism combinations. 

8 3.1.3.2.1 Cumulative Fatigue Damage 

9 Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

10 accordance with 10 CFR 54.21(c)(1). The NRC staff reviews the evaluation of this TLAA 

11 separately following the guidance in Section 4.3 of this SRP-SLR. 

12 3.1.3.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

13 1. An augmented program is recommended for the management of loss of material due to 

14 general, pitting, and crevice corrosion for steel PWR SG shell assembly exposed to 

15 secondary feedwater and steam. The existing program relies on control of water 

16 chemistry to mitigate corrosion and ISI to detect loss of material. The extent and 

17 schedule of the existing SG inspections are designed to ensure that flaws cannot attain 

18 a depth sufficient to threaten the integrity of the welds. However, according to NRC 

19 IN 90-04, the program may not be sufficient to detect pitting and crevice corrosion, if 

20 general and pitting corrosion of the shell is known to exist. Therefore, an augmented 

21 inspection is recommended to manage this aging effect. Furthermore, this issue is 

22 limited to Westinghouse Model 44 and 51 Steam Generators where a high-stress region 

23 exists at the shell to transition cone weld. Acceptance criteria are described in 

24 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). Loss of material due to general, 

25 pitting, and crevice corrosion could also occur for the steel top head enclosure 

26 (without cladding) top head nozzles [vent, top head spray or reactor core isolation 

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

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

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

30 locations of stagnant flow conditions. Therefore, the effectiveness of the water 

31 chemistry control program should be verified to ensure that corrosion is not occurring. 

32 The reviewer verifies on a case-by-case basis that the applicant has proposed a 

33 program that will manage loss of material due to general, pitting and crevice corrosion by 

34 providing enhanced inspection and supplemental methods to detect loss of material and 

35 ensure that the component-intended function will be maintained during the subsequent 

36 period of extended operation. 

37 2. Further evaluation is recommended of programs to manage the loss of material due to 

38 general, pitting, and crevice corrosion for the new transition cone closure weld generated 

39 in the steel PWR replacement recirculating steam generator transition cone shell 

40 exposed to secondary feedwater and steam. The existing program relies on control of 

41 reactor water chemistry to mitigate corrosion and on ISI to detect loss of material. The 

42 reviewer verifies on a case-by-case basis that the applicant has proposed an augmented 

43 program that will manage loss of material due to general, pitting, and crevice corrosion 

44 and ensure that the component-intended function will be maintained during the 

45 subsequent period of extended operation. 
3.1-16 

1 The reviewer verifies that the applicant has described the surface condition and the 

2 resultant flow near the new transition cone closure weld (e.g., weld crown, ground flush, 

3 etc.) and how these parameters could affect the susceptibility of this weld to this aging 

4 effect, relative to that of the upper and lower transition welds. Based on this information, 

5 the reviewer verifies whether any additional aging management of the new transition 

6 weld is necessary. If additional aging management is necessary, the reviewer verifies 

7 whether the applicant has described an AMP of the new transition cone closure weld 

8 (including examination frequency and technique) that will be effective in managing an 

9 aging effect, such as the loss of material due to general, pitting, and crevice corrosion 

10 during the subsequent period of extended operation for the new transition cone 

11 closure weld. 

12 3.1.3.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

13 1. Neutron irradiation embrittlement is a TLAA as defined in 10 CFR 54.3. TLAAs are 

14 required to be evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews 

15 the evaluation of this TLAA following the guidance in Section 4.2 of this SRP-SLR. 

16 2. Neutron irradiation embrittlement is a TLAA as defined in 10 CFR 54.3. TLAAs are 

17 required to be evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews 

18 the evaluation of this TLAA following the guidance in Section 4.2 of this SRP-SLR. 

19 Further evaluation is recommended for a reactor vessel materials surveillance program 

20 for the subsequent period of extended operation to monitor neutron embrittlement of the 

21 reactor vessel. The reactor vessel surveillance program is plant-specific, depending on 

22 matters such as the composition of limiting materials, availability of surveillance. A 

23 neutron fluence monitoring program is used to monitor the neutron fluence levels that 

24 are used as the time-dependent inputs for those reactor vessel neutron irradiation 

25 embrittlement TLAAs that are the subject of the topics in SRP-SLR Section 3.1.2.2.3, 

26 Subsection 1, and SRP-SLR Section 4.2. 

27 In accordance with 10 CFR Part 50, Appendix H, an applicant must submit its proposed 

28 capsule withdrawal schedule for approval prior to implementation. Untested capsules 

29 placed in storage must be maintained for future insertion. Thus, further NRC staff 

30 evaluation is required for SLR. The reviewer verifies on a case-by-case basis that the 

31 applicant has proposed an adequate reactor vessel materials surveillance program for 

32 the subsequent period of extended operation. The reviewer also verifies on a case-by33 case basis that the applicant has proposed an acceptable neutron fluence monitoring 

34 AMP for the subsequent period of extended operation. Specific recommendations for 

35 acceptable AMPs are provided in GALL-SLR Report AMP XI.M31, “Reactor Vessel 

36 Surveillance,” for reactor vessel material surveillance programs and GALL-SLR Report 

37 AMP X.M2, “Neutron Fluence Monitoring,” for neutron fluence monitoring programs. 

38 3. Reduction in Fracture Toughness for B&W reactor internals is a TLAA as defined 

39 in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 

40 10 CFR 54.21(c)(1). The NRC staff reviews the evaluation of this TLAA following the 

41 guidance in Section 4.7 of this SRP-SLR consistent with the action item documented in 

42 the NRC staff’s safety evaluation for MRP-227, Revision 0. 
3.1-17 

1 3.1.3.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

2 Corrosion Cracking 

3 1. A plant-specific AMP should be evaluated to manage cracking due to SCC and IGSCC 

4 in SS and nickel alloy BWR top head enclosure vessel flange leak detection lines. The 

5 reviewer reviews the applicant’s proposed program on a case-by-case basis to ensure 

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

7 2. An augmented program is recommended to include temperature and radioactivity 

8 monitoring of the shell-side water and eddy current testing of tubes for the management 

9 of cracking due to SCC and IGSCC of the SS BWR isolation condenser components. 

10 The existing program relies on control of reactor water chemistry to mitigate SCC and 

11 IGSCC and on ASME Section XI ISI to detect leakage. However, the existing program 

12 should be augmented to detect cracking due to SCC and IGSCC. The reviewer reviews 

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

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

15 3.1.3.2.5 Crack Growth Due to Cyclic Loading 

16 Further evaluation is recommended of programs to manage crack growth due to cyclic loading 

17 in reactor vessel shell forgings clad with SS using a high-heat-input welding process. Growth of 

18 intergranular separations (underclad cracks) in the heat affected zone under austenitic SS 

19 cladding is a TLAA to be evaluated for the subsequent period of extended operation for all the 

20 SA-508-Cl-2 forgings where the cladding was deposited with a high-heat-input welding process. 

21 The methodology for evaluating the underclad flaw should be consistent with the current 

22 well-established flaw evaluation procedure and criterion in the ASME Section XI Code. The 

23 SRP-SLR, Section 4.7 provides generic guidance for meeting the requirements of 

24 10 CFR 54.21(c). The NRC staff reviews the evaluation of this TLAA separately following the 

25 guidance in Section 4.7 of this SRP-SLR Report. 

26 3.1.3.2.6 Cracking Due to Stress Corrosion Cracking 

27 1. A plant-specific AMP should be evaluated to manage cracking due to SCC in SS PWR 

28 reactor vessel flange leak detection lines and bottom-mounted instrument guide tubes 

29 exposed to reactor coolant. The reviewer reviews the applicant’s proposed program on 

30 a case-by-case basis to ensure that an adequate program will be in place for the 

31 management of these aging effects. 

32 2. A plant-specific AMP should be evaluated to manage cracking due to SCC in CASS 

33 PWR Class 1 reactor coolant system piping and piping components exposed to reactor 

34 coolant that do not meet the carbon and ferrite content guidelines of NUREG–0313. The 

35 reviewer reviews the applicant’s proposed program on a case-by-case basis to ensure 

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

37 3.1.3.2.7 Cracking Due to Cyclic Loading 

38 An augmented program for the management of cracking due to cyclic loading in steel and SS 

39 BWR isolation condenser components is recommended. The existing program relies on 

40 ASME Section XI ISI for detection. However, the inspection requirements should be augmented 

41 to detect cracking due to cyclic loading. An augmented program to include temperature and 

42 radioactivity monitoring of the shell-side water and eddy current testing of tubes is 
3.1-18 

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

2 subsequent period of extended operation. The reviewer verifies on a case-by-case basis that 

3 the applicant has proposed an augmented program that will detect cracking and ensure that 

4 the component-intended function will be maintained during the subsequent period of 

5 extended operation. 

6 3.1.3.2.8 Loss of Material Due to Erosion 

7 Further evaluation of a plant-specific AMP is recommended for the management of loss of 

8 material due to erosion of steel steam generator feedwater impingement plates and supports 

9 exposed to secondary feedwater. The reviewer reviews the applicant’s proposed program on a 

10 case-by-case basis to ensure that an adequate program will be in place for the management of 

11 these aging effects. 

12 3.1.3.2.9 Aging Management of PWR Reactor Vessel Internals (Applicable to Subsequent 

13 License Renewal Periods Only) 

14 EPRI TR No. 1022863, “Materials Reliability Program: Pressurized Water Reactor Internals 

15 Inspection and Evaluation Guidelines (MRP-227-A)” (henceforth TR MRP-227-A, which may be 

16 accessed at ADAMS Accession Nos. ML12017A191 through ML12017A197 and 

17 ML12017A199), provides the industry’s current aging management recommendations for the 

18 RVI components that are included in the design of a PWR facility. In this report, the EPRI MRP 

19 identified that the following aging mechanisms may be applicable to the design of the RVI 

20 components in these types of facilities: (a) SCC, (b) IASCC, (c) fatigue, (d) wear, (e) neutron 

21 irradiation embrittlement, (f) thermal aging embrittlement, (g) void swelling and irradiation 

22 growth, or (h) thermal or irradiation-enhanced stress relaxation or irradiation enhanced creep. 

23 The methodology in TR MRP-227-A was approved by the NRC in a safety evaluation dated 

24 December 16, 2011 (ML11308A770), which includes those plant-specific applicant/licensee 

25 action items that a licensee or applicant applying the MRP-227-A report would need to address 

26 and resolve and apply to its licensing basis. 

27 The EPRI MRP does not currently assess whether potential operations of Westinghouse28 designed, B&W-designed and CE-designed reactors during a subsequent period of extended 

29 operation would have any impact on the existing susceptibility rankings and inspection 

30 categorizations for the RVI components in these designs, as defined in TR MRP-227-A or its 

31 applicable MRP issued background documents (e.g., TR MRP-191 for Westinghouse-designed 

32 or CE-designed RVI components or MRP-189 for B&W-designed components). Therefore, for 

33 SLRAs of PWR facilities, a plant-specific AMP for the RVI components is needed to 

34 demonstrate that the RVI components will be managed in accordance with the requirements of 

35 10 CFR 54.21(a)(3) during a proposed subsequent period of extended operation. The reviewer 

36 reviews the adequacy of the applicant’s AMP on a case-by-case basis against the criteria for 

37 plant-specific AMP program elements defined in Sections A.1.2.3.1 through A.1.2.3.10 of 

38 SRP-SLR Appendix A.1. The reviewer verifies that the applicant has defined both the type of 

39 performance monitoring, condition monitoring, preventative monitoring, or mitigative monitoring 

40 AMP that will be used for aging management of the RVI components and the specific program 

41 element criteria for the AMP that will be used to manage age-related effects in the RVI 

42 components during the SLR period. 

43 If a plant-specific sampling-based condition monitoring program is proposed as the AMP for the 

44 components, the reviewer verifies that the applicant has appropriately identified (with adequate 

45 justification) the population of RVI components that are within the scope of the program, and the 
3.1-19 

1 specific RVI components that will be inspected by the AMP. The reviewer also verifies that the 

2 applicant has appropriately identified the aging effects that will be monitored, the components in 

3 the inspection sample, and the inspection methods and frequency that will be applied to the 

4 components. The reviewer also verifies that program includes applicable inspection expansion 

5 criteria that will be applied under the program if inspections of the RVI components results in 

6 identification of relevant age-related aging effects or mechanisms. In addition, the reviewer 

7 verifies that the program includes appropriate acceptance criteria for evaluating the inspection 

8 results of the AMP and appropriate corrective action criteria that will be implemented if these 

9 acceptance criteria are not met. Applicant bases for resolving specific Technical Report or TR 

10 applicant/licensee action items will be within the scope of the NRC’s review of the AMP. Refer 

11 to SRP-SLR Section 3.0 and SRP-SRP Appendix A.1 for additional information. 

12 3.1.3.2.10 Loss of Material Due to Wear 

13 1. Loss of material due to wear can occur in PWR CRD head penetration nozzles 

14 due to the interactions between the nozzle and the thermal sleeve centering 

15 pads of the nozzle. The applicant should perform a further evaluation to confirm 

16 the adequacy of a plant-specific AMP or analysis (with any necessary 

17 inspections) for management of the aging effect. The reviewer confirms that the 

18 applicant’s plant-specific AMP for managing this aging effect meets the 

19 acceptance criteria that are described in BTP RLSB-1 (Appendix A.1 of this 

20 SRP-SLR Report). Alternatively, the reviewer confirms that loss of material due 

21 to wear does not affect the intended function(s) of CRD head penetration 

22 nozzles, consistent with the CLB, if the applicant relies on an analysis for aging 

23 management. The reviewer also confirms whether inspections are necessary to 

24 ensure the adequacy of the analysis. 

25 2. Loss of material due to wear can occur in the thermal sleeves of PWR CRD 

26 head penetration nozzles due to the interactions between the nozzle and the 

27 thermal sleeve. The applicant should perform a further evaluation to confirm the 

28 adequacy of a plant-specific AMP for management of the aging effect. The 

29 reviewer confirms that the applicant’s plant-specific AMP for managing this aging 

30 effect meets the acceptance criteria that are described in BTP RLSB-1 

31 (Appendix A.1 of this SRP-SLR Report). 

32 3.1.3.2.11 Cracking Due to Primary Water Stress Corrosion Cracking 

33 1. A plant-specific AMP should be evaluated, along with the primary water chemistry 

34 program, to manage cracking due to PWSCC in nickel alloy divider plate assemblies 

35 made of Alloy 600 and/or the associated Alloy 600 weld materials for SGs with a similar 

36 design to that of Westinghouse Model 51. The effectiveness of the chemistry control 

37 program should be verified to ensure that cracking due to PWSCC is not occurring. The 

38 reviewer verifies the materials of construction of the applicant’s SG divider plate 

39 assembly. If these materials are susceptible to cracking, the reviewer verifies that the 

40 applicant has evaluated the potential for cracking in the divider plate to propagate into 

41 other components (e.g., tubesheet cladding). If propagation into these other 

42 components is possible, the reviewer verifies if the applicant has described an inspection 

43 program (examination technique and frequency) for ensuring that no cracks are 

44 propagating into other items (e.g., tube sheet and channel head) that could challenge 

45 the integrity of those items. The reviewer reviews the applicant’s proposed program on 
3.1-20 

1 a case-by-case basis to ensure that an adequate program will be in place for the 

2 management of this aging effect. 

3 2. A plant-specific AMP should be evaluated, along with the primary water chemistry 

4 program, to manage cracking due to PWSCC in recirculating SG nickel alloy tube-to5 tubesheet welds exposed to reactor coolant. The effectiveness of the primary water 

6 chemistry program should be verified to ensure that cracking due to PWSCC is not 

7 occurring. The reviewer verifies the combination of materials of construction of the SG 

8 tubes and tubesheet cladding and the classification of the tube-to-tubesheet weld. If this 

9 combination requires further evaluation, the reviewer reviews the applicant’s proposed 

10 program on a case-by-case basis to ensure that an adequate program will be in place for 

11 the management of this aging effect. 

12 3.1.3.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking 

13 1. Cracking due to IASCC can occur in BWR vessel internals made of nickel alloy 

14 and SS. The applicant should perform an evaluation to determine whether 

15 supplemental inspections are necessary in addition to the existing BWRVIP 

16 examination guidelines to adequately manage cracking due to IASCC for BWR 

17 vessel internals. This evaluation for supplemental inspections is based on 

18 neutron fluence and cracking susceptibility (i.e., applied stress, operating 

19 temperature, and environmental conditions). The NRC staff reviews the 

20 applicant’s evaluation to ensure that adequate supplemental inspections are 

21 identified and included in the applicant’s BWR Vessel Internals Program as 

22 necessary for aging management of cracking due to IASCC. In addition, any 

23 necessary enhancements to the BWRVIP should be reviewed for 

24 adequate justification. 

25 2. Cracking due to IASCC can occur in the BWR core shroud support plate access 

26 hole cover (welded or mechanical). The applicant should perform an evaluation 

27 to determine whether supplemental inspections are necessary in addition to the 

28 existing ISI to adequately manage cracking due to IASCC for this component for 

29 the subsequent period of extended operation. This evaluation is based on 

30 neutron fluence and cracking susceptibility (i.e., applied stress, operating 

31 temperature, and environmental conditions). The NRC staff reviews the 

32 applicant’s evaluation to ensure that adequate supplemental inspections are 

33 identified and included in the applicant’s aging management for this component 

34 as necessary. In addition, any necessary enhancements to the ASME 

35 Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program 

36 should be reviewed for adequate justification. 

37 3.1.3.2.13 Loss of Fracture Toughness Due to Neutron Irradiation or Thermal 

38 Aging Embrittlement 

39 Loss of fracture toughness due to neutron irradiation embrittlement can occur in BWR 

40 vessel internals made of nickel alloy and SS. In addition, loss of fracture toughness due 

41 to neutron irradiation and thermal aging embrittlement can occur in BWR vessel 

42 internals made of CASS, PH martensitic SS (e.g., 15-5 and 17-4 PH steel) and 

43 martensitic SS (e.g., 403, 410, 431 steel). 
3.1-21 

1 The applicant should perform an evaluation to determine whether supplemental 

2 inspections are necessary in addition to the existing BWRVIP examination guidelines to 

3 adequately manage loss of fracture toughness for BWR vessel internals. This 

4 evaluation for supplemental inspections is based on neutron fluence, thermal aging 

5 susceptibility, fracture toughness, and cracking susceptibility (i.e., applied stress, 

6 operating temperature, and environmental conditions). The NRC staff reviews the 

7 applicant’s evaluation to ensure that adequate supplemental inspections are identified 

8 and included in the applicant’s BWRVIP as necessary for aging management of loss of 

9 fracture toughness. In addition, any necessary enhancements to the BWRVIP should 

10 be reviewed for adequate justification.

11 3.1.3.2.14 Loss of Preload Due to Thermal or Irradiation-Enhanced Stress Relaxation 

12 GALL-SLR Report AMP XI.M9 of the GALL-SLR Report, “BWR Vessel Internals,” manages loss 

13 of preload due to thermal or irradiation-enhanced stress relaxation in BWR core plate rim 

14 holddown bolts. The issue is applicable to BWR light water reactors that employ rim holddown 

15 bolts as the means for protecting the reactor’s core plate from the consequences of lateral 

16 movement. The potential for such movement, if left unmanaged, could impact the ability of the 

17 reactor to be brought into a safe shutdown condition during an anticipated transient occurrence 

18 or during a postulated design-basis accident or seismic event. This issue is not applicable to 

19 BWR reactor designs that use wedges as the means of precluding lateral movement of the core 

20 plate because the wedges are fixed in place and are not subject to this type of aging effect and 

21 mechanism combination. 

22 GALL-SLR Report AMP XI.M9 states that the inspections in BWRVIP TR No. BWRVIP-25, 

23 “BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines 

24 (BWRVIP-25),” is used to manage loss of preload due to thermal or irradiation-enhanced stress 

25 relaxation in BWR designs with core plate rim holddown bolts. However, in initial LRAs, some 

26 applicants have identified that the inspection bases for managing loss of preload in TR 

27 No. BWRVIP-25 may not be capable of gaining access to the rim holddown bolts or are not 

28 sufficient to detect loss of preload on the components. For applicants that have identified this 

29 issue in their past LRAs, the applicants have committed to modifying the plant design to install 

30 wedges in the core plate designs or to submitting an inspection plan, with a supporting core 

31 plate rim holddown bolt preload analysis for NRC approval at least 2 years prior to entering the 

32 subsequent period of extended operation for the facility. 

33 For SLRAs that apply to BWRs with core plate rim holddown bolts, the reviewer assesses 

34 whether the SLRA has included an enhanced augmented inspection basis for plants’ core plate 

35 rim holddown bolts and has justified the augmented inspection basis that will be applied to the 

36 components, along with a supporting loss of preload analysis that supports the augmented 

37 inspection method and frequency that will be applied to the bolts. If an existing NRC-approved 

38 analysis for the bolts exists in the CLB and conforms to the definition of a TLAA, the reviewer 

39 assesses whether the applicant has identified the analysis as a TLAA for the SLRA and has 

40 demonstrated why the analysis is acceptable in accordance with either 10 CFR 54.21(c)(1)(i), 

41 (ii), or (iii). Otherwise, if a new analysis will be performed to support an updated 80-year 

42 augmented inspection basis for the bolts for the subsequent period of extended operation, the 

43 NRC staff reviews the applicant’s augmented inspection and evaluation basis to determine 

44 whether the FSAR Supplement for the LRA has included a license commitment to submit both 

45 the inspection plan and the supporting loss of preload analysis to the NRC staff at least 2 years 

46 prior to entering into the subsequent period of extended operation for the facility. 
3.1-22 

1 3.1.3.2.15 Loss of Material Due to Boric Acid Corrosion 

2 A plant-specific AMP should be evaluated, along with the Water Chemistry program, to 

3 adequately manage loss of material due to boric acid corrosion for the steel base material of the 

4 SG head. The reviewer should review the plant-specific program to ensure that the program is 

5 capable of managing loss of material due to boric acid corrosion for the steam generator head 

6 base material. If the channel head cladding is compromised or steel base material is corroded, 

7 the reviewer assesses whether additional analytical evaluations or inspections are necessary in 

8 order to ensure that the potential loss of material in the SG head will not affect the integrity of 

9 the component.

10 3.1.3.2.16 Cracking Due to Cyclic Loading 

11 1. As discussed in NUREG–0619, rerouting the control rod drive return line was a measure 

12 taken by some licensees to prevent high cyclic thermal loading that had led to cracking 

13 of the control rod drive return line nozzles and the reactor pressure vessel wall in BWRs. 

14 As a result, in response to NRC Generic Letter (GL) 80-95, some BWR licensees cut 

15 and capped the control rod drive return line nozzle and rerouted the return line to an inlet 

16 piping system that delivers the return line flow to the reactor pressure vessel (RPV). 

17 While this approach eliminated the thermal gradients in the control rod drive return line 

18 nozzle in the reactor pressure vessel, it introduced lower magnitude thermal gradients at 

19 the welded connection between the rerouted control rod drive return line piping and the 

20 inlet piping system. Section 8.2 of NUREG–0619 recommends periodic inspections of 

21 this welded connection to detect potential cracking caused by the cyclical loads from 

22 these thermal gradients. 

23 The reviewer evaluates the adequacy of the applicant’s condition monitoring activities to 

24 ensure that cracking will be detected before there is a loss of intended function at this 

25 welded connection. The reviewer either confirms that the applicant will follow the 

26 recommendations in NUREG–0619, Section 8.2; or evaluates the applicant’s proposed 

27 condition monitoring activities on a case-by-case basis. 

28 The CRD return lines were eliminated from some of the newer-vintage BWR-4, BWR-5, 

29 and BWR-6 designs that were still under construction when NUREG–0619 was 

30 published. For these cases, the reviewer confirms that the plant configuration does not 

31 include a CRD return line. 

32 Cracking due to cyclic loading could occur in BWR-2 steel with or without SS cladding 

33 control rod drive return line nozzles and their nozzle-to-vessel welds exposed to reactor 

34 coolant. The reviewer reviews the applicant’s proposed program on a case-by-case 

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

36 aging effect. 

37 3.1.3.2.17 Cracking Due to Stress Corrosion Cracking or Intergranular Stress 

38 Corrosion Cracking 

39 A review is recommended of plant-specific AMPs for managing cracking due to SCC and 

40 IGSCC in BWR SS and nickel alloy piping and piping components greater than or equal to 

41 4 inches NPS; nozzle safe ends and associated welds; and CRD return line nozzle caps and the 

42 associated cap-to-nozzle welds or cap-to-safe end welds in BWR-3, BWR-4, BWR-5, and 

43 BWR-6 designs that are exposed to reactor coolant. Components in dead-legs and other piping 
3.1-23 

1 locations with stagnant flow may be subject to localized environmental conditions that could 

2 exacerbate the mechanisms of SCC and IGSCC. The reviewer ensures that the applicant has 

3 identified any such locations and provided justification for the AMPs credited for managing this 

4 aging effect. The reviewer reviews the applicant’s justification and proposed AMPs on a 

5 case-by-case basis to ensure that the effects of aging will be adequately managed. 

6 3.1.3.2.18 Loss of Material Due to General, Crevice or Pitting Corrosion and 

7 Microbiologically-Induced Corrosion and Cracking Due to Stress 

8 Corrosion Cracking 

9 For steel piping and piping components exposed to concrete, if the following conditions are met, 

10 loss of material is not considered to be an applicable aging effect for steel: (a) attributes of the 

11 concrete are consistent with American Concrete Institute (ACI) 318 or ACI 349 (low water-to12 cement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557; (b) 

13 plant-specific operating experience indicates no degradation of the concrete that could lead to 

14 penetration of water to the metal surface; and (c) the piping is not potentially exposed to 

15 groundwater. For SS piping and piping components, loss of material and cracking due to SCC 

16 are not considered to be applicable aging effects as long as the piping is not potentially 

17 exposed to groundwater. Where these conditions are not met, loss of material due to general 

18 (steel only), crevice, or pitting corrosion, and microbiologically-induced corrosion and cracking 

19 due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

20 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

21 these aging effects. 

22 The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-to23 cement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

24 reviewer should evaluate plant-specific operating experience to determine whether concrete 

25 degradation sufficient to allow water intrusion has occurred. 

26 3.1.3.2.19 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically27 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

28 Water, or Sodium Pentaborate Solution 

29 Loss of material due to crevice corrosion can occur in steel with SS cladding, SS, and nickel 

30 alloy piping, piping components, heat exchanger components, spent fuel storage racks, tanks, 

31 and PWR heat exchanger components exposed to treated water, treated borated water, or 

32 sodium pentaborate solution if oxygen levels are greater than 100 ppb. In addition, loss of 

33 material due to pitting can occur if oxygen levels are greater than 100 ppb, halides or sulfates 

34 levels are greater than 150 ppb, and stagnant flow conditions exist. Loss of material due to 

35 microbiologically-induced corrosion can occur with steel with SS cladding, SS, and nickel alloy 

36 piping, piping components, heat exchanger components, spent fuel storage racks, tanks, and 

37 PWR heat exchanger components exposed to treated water, treated borated water, or sodium 

38 pentaborate solution if the pH is less than 10.5 and temperature is less than 99 °C [210 °F]. 

39 The reviewer verifies the applicant’s chemistry control parameters to determine whether 

40 GALL-SLR Report AMP XI.M2, “Water Chemistry,” and a one-time inspection program is 

41 implemented (e.g., GALL-SLR Report AMP XI.M32, “One-Time Inspection”) or GALL-SLR 

42 Report AMP XI.M2, “Water Chemistry,” and a periodic inspection program is implemented 

43 (e.g., GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

44 and Ducting Components”) to manage loss of material. 
3.1-24 

1 3.1.3.2.20 Quality Assurance for Aging Management of Nonsafety-Related Components 

2 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

3 confirmation process, and administrative controls. Safety-related components are covered by 

4 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

5 Appendix B does not apply to nonsafety-related components that are subject to an AMR for 

6 SLR. Nevertheless, the applicant has the option to expand the scope of its 10 CFR Part 50, 

7 Appendix B program to include these components and address the associated program 

8 elements. If the applicant chooses this option, the reviewer verifies that the applicant has 

9 documented such a commitment in the FSAR Supplement. If the applicant chooses alternative 

10 means, the branch responsible for quality assurance (QA) should be requested to review the 

11 applicant’s proposal on a case-by-case basis. 

12 3.1.3.2.21 Ongoing Review of Operating Experience 

13 The applicant’s AMPs should contain the element of operating experience. The reviewer 

14 verifies that the applicant has appropriate programs or processes for the ongoing review of both 

15 plant-specific and industry operating experience concerning age-related degradation and aging 

16 management. Such reviews are used to ensure that the AMPs are effective to manage the 

17 aging effects for which they are created. The AMPs are either enhanced or new AMPs are 

18 developed, as appropriate, when it is determined through the evaluation of operating experience 

19 that the effects of aging may not be adequately managed. Additional information is in 

20 Appendix A.4, “Operating Experience for AMPs.” 

21 In addition, the reviewer confirms that the applicant has provided an appropriate summary 

22 description of these activities in the FSAR supplement. An example description is under 

23 “Operating Experience” in Table 3.0-1, “FSAR Supplement for Aging Management of 

24 Applicable Systems for SLR.” 

25 3.1.3.3 Aging Managing Review Results Not Consistent With or Not Addressed in the 

26 Generic Aging Lessons Learned for Subsequent License Renewal Report 

27 The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging 

28 effects, listed the appropriate combination of materials and environments, and AMPs that will 

29 adequately manage the aging effects. The AMP credited by the applicant could be an AMP that 

30 is described and evaluated in the GALL-SLR Report or a plant-specific program. Review 

31 procedures are described in BTP RSLB-1 (Appendix A.1 of this SRP-SLR Report). 

32 3.1.3.4 Aging Management Programs 

33 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

34 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

35 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

36 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

37 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

38 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

39 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

40 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP, with which 

41 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

42 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

43 enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 
3.1-25 

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

2 Table 3.1-1 of this SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in 

3 the GALL-SLR Report, Chapter IV, presenting detailed information summarized by this row. 

4 3.1.3.5 Final Safety Analysis Report Supplement 

5 The reviewer confirms that the applicant has provided in its FSAR supplement information 

6 equivalent to that in Table 3.0-1 for aging management of the reactor vessel, internals, and 

7 reactor coolant system. Table 3.1-2 lists the AMPs that are applicable for this SRP-SLR 

8 subsection. The reviewer also confirms that the applicant has provided information for 

9 Subsection 3.1.3.3, “AMR Results Not Consistent with or Not Addressed in the GALL-SLR 

10 Report,” equivalent to that in Table 3.0-1. 

11 The NRC staff expects to impose a license condition on any renewed license to require the 

12 applicant to update its FSAR to include this FSAR Supplement at the next update required 

13 pursuant to 10 CFR 50.71(e)(4). As part of the license conditions until the FSAR update is 

14 complete, the applicant may make changes to the programs described in its FSAR Supplement 

15 without prior NRC approval, provided that the applicant evaluates each such change and finds it 

16 acceptable pursuant to the criteria set forth in 10 CFR 50.59. If the applicant updates the 

17 FSAR to include the final FSAR supplement before the license is renewed, no condition will 

18 be necessary. 

19 As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

20 FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

21 the SLRA to any future aging management activities, including enhancements and 

22 commitments to be completed before entering the subsequent period of extended operation. 

23 The NRC staff expects to impose a license condition on any renewed license to ensure that the 

24 applicant will complete these activities no later than the committed date. 

25 3.1.4 Evaluation Findings 

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

27 provisions of this section, then an evaluation finding similar to the following text should be 

28 included in the NRC staff’s safety evaluation report: 

29 On the basis of its review, as discussed above, the NRC staff concludes that the 

30 applicant has demonstrated that the aging effects associated with the reactor 

31 vessel, internals, and reactor coolant system components will be adequately 

32 managed so that the intended functions will be maintained consistent with the 

33 CLB for the subsequent period of extended operation, as required by 

34 10 CFR 54.21(a)(3). 

35 The NRC staff also reviewed the applicable FSAR Supplement program 

36 summaries and concludes that they adequately describe the AMPs credited for 

37 managing aging of the reactor vessel, internals and reactor coolant system, as 

38 required by 10 CFR 54.21(d). 
3.1-26 

1 3.1.5 Implementation 

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

3 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

5 3.1.6 References 

6 1. NEI. NEI 97-06, “Steam Generator Program Guidelines.” Revision 2. Washington, DC: 

7 Nuclear Energy Institute. September 2005. 

8 2. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

9 10 CFR Part 54–The License Renewal Rule.” Revision 6. Washington, DC: Nuclear 

10 Energy Institute. 

11 3. NRC. Information Notice 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth 

12 Welds in Steam Generators.” Washington, DC: U.S. Nuclear Regulatory Commission. 

13 January 26, 1990. 

14 4. NRC. NUREG–0313, “Technical Report on Material Selection and Processing 

15 Guidelines for BWR Coolant Pressure Boundary Piping.” Revision 2. Washington, DC: 

16 U.S. Nuclear Regulatory Commission. January 1988. 

17 5. EPRI. EPRI 1013706, “PWR Steam Generator Examination Guidelines. Revision 7. 

18 Palo Alto, California: Electric Power Research Institute. October 2007. 

19 6. NRC. Regulatory Guide 1.121, “Bases for Plugging Degraded PWR Steam Generator 

20 Tubes (for Comment).” Washington, DC: U.S. Nuclear Regulatory Commission. 

21 May 1976. 

22 7. NRC. Generic Letter 95-05, “Voltage-Based Repair Criteria for Westinghouse Steam 

23 Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking.” 

24 Washington, DC: U.S. Nuclear Regulatory Commission. August 3, 1995. 

25 8. NRC. Information Notice 90-10, “Primary Water Stress Corrosion Cracking (PWSCC) of 

26 Inconel 600.” Washington, DC: U.S. Nuclear Regulatory Commission. 

27 February 23, 1990. 

28 9. NRC. Information Notice 90-30, “Ultrasonic Inspection Techniques for Dissimilar Metal 

29 Welds.” Washington, DC: U.S. Nuclear Regulatory Commission. May 1, 1990. 

30 10. NRC. Generic Letter 89-08, “Erosion/Corrosion-Induced Pipe Wall Thinning.” 

31 Washington, DC: U.S. Nuclear Regulatory Commission. May 2, 1989. 

32 11. EPRI. NSAC-202L-R3, “Recommendations for an Effective Flow-accelerated Corrosion 

33 Program.” Palo Alto, California: Electric Power Research Institute. April 1999. 

34 12. NRC. Information Notice 96-11, “Ingress of Demineralizer Resins Increase Potential for 

35 Stress Corrosion Cracking of Control Rod Drive Mechanism Penetrations.” 

36 Washington, DC: U.S. Nuclear Regulatory Commission. February 14, 1996. 
3.1-27 

1 13. EPRI. BWRVIP–190 (EPRI 1016579), BWR Vessel and Internals Project: BWR Water 

2 Chemistry Guidelines-2008 Revision. Palo Alto, California: Electric Power Research 

3 Institute. October 2008 

4 14. EPRI. NP–5769, “Degradation and Failure of Bolting in Nuclear Power Plants.” 

5 Volumes 1 and 2. Palo Alto, California: Electric Power Research Institute. April 1988. 

6 15. EPRI. TR 1014986, “PWR Primary Water Chemistry Guidelines.” Revision 6. 

7 Volumes 1 and 2. Palo Alto, California: Electric Power Research Institute. 

8 December 2007. 

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

10 Piping.” Washington, DC: U.S. Nuclear Regulatory Commission. January 25, 1988. 

11 17. NRC. Generic Letter 97-01, “Degradation of Control Rod Drive Mechanism Nozzle and 

12 Other Vessel Closure Head Penetrations.” Washington, DC: U.S. Nuclear Regulatory 

13 Commission. April 1, 1997. 

14 18. NRC. Information Notice 97-46, “Unisolable Crack in High-Pressure Injection Piping.” 

15 Washington, DC: U.S. Nuclear Regulatory Commission. July 9, 1997. 

16 19. NRC. Regulatory Guide 1.99, “Radiation Embrittlement of Reactor Vessel Materials.” 

17 Washington, DC: U.S. Nuclear Regulatory Commission. May 1988. 

18 20. NRC. NUREG–0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line 

19 Nozzle Cracking.” Washington, DC: U.S. Nuclear Regulatory Commission. 

20 November 1980. 

21 21. NRC. NUREG–1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or 

22 Failure in Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory 

23 Commission. June 1990. 

24 22. EPRI. TR-104213, “Bolted Joint Maintenance & Application Guide, Electric Power 

25 Research Institute.” Palo Alto, California: Electric Power Research Institute. 

26 December 1995. 

27 23. Dave Modeen. NEI Letter (December 11) to Gus Lainas, “Responses to NRC Requests 

28 for Additional Information (RAIs) on GL 97-01.” Washington, DC: Nuclear Energy 

29 Institute. 1998. 

30 24. EPRI. TR 1016555, “PWR Secondary Water Chemistry Guidelines–Revision 7.” 

31 Palo Alto, California: Electric Power Research Institute. February 2009. 

32 25. NRC. Information Notice 91-19, “Steam Generator Feedwater Distribution Piping 

33 Damage.” Washington, DC: U.S. Nuclear Regulatory Commission. March 12, 1991. 

34 26. EPRI. TR 1022863, “Materials Reliability Program: Pressurized Water Reactor Internals 

35 Inspection and Evaluation Guidelines (MRP-227-A).” Palo Alto, California: Electric 

36 Power Research Institute. December 2011. 
3.1-28 

1 27. Entergy Operations, Inc. “Demonstration of the Management of Aging Effects for the 

2 Reactor Vessel Internals.” Topical Report BAW-2248A. Russellville, Arkansas: Entergy 

3 Operations, Inc. March 2000. 

4 28. EPRI. TR-1014982, “Divider Plate Cracking in Steam Generators - Results of Phase 1: 

5 Analysis of Primary Water Stress Corrosion Cracking and Mechanical Fatigue in the 

6 Alloy 600 Stub Runner to Divider Plate Weld Material.” Palo Alto, California: Electric 

7 Power Research Institute. June 2007. 

8 29. Dominion Nuclear Connecticut, Inc. Letter (July 13) to NRC, Dominion Nuclear 

9 Connecticut, Inc. Millstone Power Station Unit 3 Results of the Reactor Pressure 

10 Vessel Head Inspections Required by NRC Order EA-03-009. 2007. 

11 30. Southern Company. Letter (June 21) to the NRC, Vogtle Electric Generating Plant - 

12 Unit 2 Results of Reactor Pressure Vessel Head Inspections Required by First Revised 

13 Order EA-03-009. Atlanta, Georgia: Southern Company. 2007. 
3.1-29 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 1 BWR/PWR Steel reactor vessel 

closure flange assembly components exposed to air with potential for reactor coolant leakage 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A1.RP201 IV.A2.RP-54 

M 2 PWR Nickel alloy tubes and 

sleeves exposed to reactor coolant, secondary feedwater/steam 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.D1.R-46 IV.D2.R-46 

M 3 BWR/PWR Stainless steel, nickel 

alloy reactor vessel internal components exposed to reactor coolant, neutron flux 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.B1.R-53 IV.B2.RP303 IV.B3.RP339 IV.B4.R-53 

M 4 BWR/PWR Steel pressure vessel 

support skirt and attachment welds 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.A1.R-70 IV.A2.R-70 

M 5 PWR Steel, stainless steel, 

steel (with stainless steel or nickel alloy cladding) steam generator components, pressurizer relief tank components, piping components, bolting 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C2.R-13 IV.C2.R-18 IV.D1.R-33 IV.D2.R-33 

M 6 BWR Steel (with or without 

nickel-alloy or stainless steel cladding), stainless steel; nickel alloy reactor coolant pressure 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR, Section 3.1.2.2.1) 

IV.C1.R-220 
3.1-30 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

boundary components: piping, piping components; other pressure retaining components exposed to reactor coolant 

M 7 BWR Steel (with or without 

nickel-alloy or stainless steel cladding), or stainless steel; or nickel alloy reactor vessel components: nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads and welds exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR, Section 3.1.2.2.1) 

IV.A1.R-04 

M 8 PWR Steel (with or without 

nickel-alloy or stainless steel cladding), or stainless steel; or nickel alloy steam generator components exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR, Section 3.1.2.2.1) 

IV.D1.R-221 IV.D2.R-222 

M 9 PWR Steel (with or without 

nickel-alloy or stainless steel cladding), stainless steel; nickel alloy reactor coolant pressure boundary piping, piping components; other pressure retaining components exposed to 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR, Section 3.1.2.2.1) 

IV.C2.R-223 
3.1-31 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

reactor coolant 

M 10 PWR Steel (with or without 

nickel-alloy or stainless steel cladding), stainless steel, or nickel alloy reactor vessel components: nozzles; penetrations; pressure housings; safe ends; thermal sleeves; vessel shells, heads and welds exposed to reactor coolant 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR, Section 3.1.2.2.1) 

IV.A2.R-219 

M 11 BWR Steel or stainless steel 

pump and valve closure bolting exposed to high temperatures and thermal cycles 

Cumulative fatigue damage: cracking due to fatigue, cyclical loading 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.1.2.2.1) 

IV.C1.RP-44 

M 12 PWR Steel steam generator 

components: upper and lower shells, transition cone; new transition cone closure weld exposed to secondary feedwater or steam 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Sections 3.1.2.2.2.1 and 3.1.2.2.2.2) 

IV.D1.RP368 

M 13 BWR/PWR Steel (with or without 

stainless steel or nickel alloy cladding) reactor vessel beltline shell, nozzle, and weld 

Loss of fracture toughness due to neutron irradiation embrittlement 

TLAA, SRP-SLR Section 4.2 "Reactor Vessel Neutron Embrittlement" 

Yes (SRP-SLR Section 3.1.2.2.3.1) 

IV.A1.R-62 IV.A2.R-84 
3.1-32 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

components exposed to reactor coolant and neutron flux 

M 14 BWR/PWR Steel (with or without 

cladding) reactor vessel beltline shell, nozzle, and weld components; exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement 

AMP XI.M31, "Reactor Vessel Material Surveillance," and X.M2, "Neutron Fluence Monitoring" 

Yes (SRP-SLR Section 3.1.2.2.3.2) 

IV.A1.RP227 IV.A2.RP229 

M 15 PWR Stainless steel Babcock 

& Wilcox (including CASS, martensitic SS, and PH SS) and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux 

Reduction in fracture toughness due to neutron irradiation 

TLAA, SRP-SLR Section 4.7 "Other Plant-Specific TLAAs" 

Yes (SRP-SLR Section 3.1.2.2.3.3) 

IV.B4.RP376 

M 16 BWR Stainless steel and 

nickel alloy top head enclosure vessel flange leak detection line 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.4.1) 

IV.A1.R-61 

M 17 BWR Stainless steel isolation 

condenser components exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.4.2) 

IV.C1.R-15 

M 18 PWR Reactor vessel shell 

fabricated of SA508-Cl 2 forgings clad with stainless steel using a 

Crack growth due to cyclic loading 

TLAA, SRP-SLR Section 4.7 "Other Plant-Specific TLAAs" 

Yes (SRP-SLR Section 3.1.2.2.5) 

IV.A2.R-85 
3.1-33 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

high-heat-input welding process exposed to reactor coolant 

M 19 PWR Stainless steel reactor 

vessel closure head flange leak detection line and bottom-mounted instrument guide tubes (external to reactor vessel) 

Cracking due to stress corrosion cracking 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.6.1) 

IV.A2.R-74 IV.A2.RP154 

M 20 PWR Cast austenitic stainless 

steel Class 1 piping, piping components exposed to reactor coolant 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry" and plantspecific aging management program 

Yes (SRP-SLR Section 3.1.2.2.6.2) 

IV.C2.R-05 

M 21 BWR Steel and stainless steel 

isolation condenser components exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." 

Yes (SRP-SLR Section 3.1.2.2.7) 

IV.C1.R-225 

M 22 PWR Steel steam generator 

feedwater impingement plate and support exposed to secondary feedwater 

Loss of material due to erosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.8) 

IV.D1.R-39 

M 25 PWR Steel (with nickel-alloy 

cladding) or nickel alloy steam generator primary side components: divider plate and tubeto-tube sheet welds exposed to reactor 

Cracking due to primary water stress corrosion cracking 

AMP XI.M2, "Water Chemistry" and plantspecific aging management program 

Yes (SRP-SLR Sections 3.1.2.2.11.1 for divider plates and 3.1.2.2.11.2 for tube to tube sheet welds) 

IV.D1.RP367 IV.D1.RP385 IV.D2.RP185 
3.1-34 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

coolant 

D 28 M 29 BWR Nickel alloy core shroud 

and core plate access hole cover (welded covers) exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, irradiation-assisted stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12.2) 

IV.B1.R-94 

 30 BWR Stainless steel, nickel 

alloy penetration: drain line exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.A1.RP371 

 31 BWR Steel and stainless steel 

isolation condenser components exposed to reactor coolant 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C1.RP-39 

D 32 
3.1-35 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 33 PWR Stainless steel, steel 

with stainless steel cladding Class 1 reactor coolant pressure boundary components exposed to reactor coolant 

Cracking due to stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.R-09 

IV.C2.R-217 IV.C2.R-30 IV.C2.RP344 IV.D1.RP232 

M 34 PWR Stainless steel, steel 

with stainless steel cladding pressurizer relief tank (tank shell and heads, flanges, nozzles) exposed to treated borated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.RP231 

M 35 PWR Stainless steel, steel 

with stainless steel cladding reactor coolant system cold leg, hot leg, surge line, and spray line piping and fittings exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-56 

M 36 PWR Steel, stainless steel 

pressurizer integral support exposed to air with metal temperature up to 288°C (550°F) 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-19 

M 37 PWR Steel reactor vessel 

flange 

Loss of material due to wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A2.R-87 
3.1-36 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 38 BWR/PWR Cast austenitic stainless 

steel Class 1 valve bodies and bonnets exposed to reactor coolant >250 °C (>482 °F) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." For pump casings and valve bodies, screening for susceptibility to thermal aging is not necessary. The ASME Section XI inspection requirements are sufficient for managing the effects of loss of fracture toughness due to thermal aging embrittlement of CASS valve bodies. 

No IV.C1.R-08 

IV.C2.R-08 

M 39 BWR/PWR Steel (with or without 

stainless steel or nickel alloy cladding), stainless steel, or nickel alloy Class 1 piping, fittings and branch connections < NPS 4 exposed to reactor coolant 

Cracking due to stress corrosion cracking (for stainless steel or nickel alloy surfaces exposed to reactor coolant only), intergranular stress corrosion cracking (for stainless steel or nickel alloy surfaces exposed to reactor coolant only), or thermal, mechanical, or vibratory loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," AMP XI.M2, "Water Chemistry," and XI.M35, "One-Time Inspection of ASME Code Class 1 SmallBore Piping" 

No IV.C1.RP230 

IV.C2.RP235 
3.1-37 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 40 PWR Steel with stainless steel 

or nickel alloy cladding; or stainless steel pressurizer components exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.C2.R-58 

M 40a PWR Nickel alloy core support 

pads; core guide lugs exposed to reactor coolant 

Cracking due to primary water stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-57 

M 41 BWR Nickel alloy core shroud 

and core plate access hole cover (mechanical covers) exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, irradiation-assisted stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12.2) 

IV.B1.R-95 

M 42 PWR Steel with stainless steel 

or nickel alloy cladding; stainless steel primary side components; steam generator upper and lower heads, and tube sheet welds; pressurizer components exposed to reactor coolant 

Cracking due to stress corrosion cracking, primary water stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.C2.R-25 

IV.D2.RP-47 

M 43 BWR Stainless steel and 

nickel alloy reactor vessel internals exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, 

No IV.B1.RP-26 
3.1-38 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

IWC, and IWD," and AMP XI.M2, "Water Chemistry" 

M 44 PWR Steel steam generator 

secondary manways and handholds (cover only) exposed to air with leaking secondary-side water and/or steam 

Loss of material due to erosion 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.D2.R-31 

 45 PWR Nickel alloy and steel 

with nickel-alloy cladding reactor coolant pressure boundary components exposed to reactor coolant 

Cracking due to primary water stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry," and, for nickel-alloy, AMP XI.M11B, "Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-induced Corrosion in RCPB Components (PWRs Only)" 

No IV.A2.R-90 

IV.A2.RP186 IV.A2.RP-59 IV.C2.RP156 IV.C2.RP159 IV.C2.RP-37 IV.D1.RP-36 IV.D2.RP-36 

 46 PWR Stainless steel, nickel 

alloy, nickel alloy welds and/or buttering control rod drive head penetration pressure housing or nozzle safe ends and welds (inlet, 

Cracking due to stress corrosion cracking, primary water stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry," and, for 

No IV.A2.RP234 
3.1-39 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

outlet, safety injection) exposed to reactor coolant 

nickel-alloy, AMP XI.M11B, "Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-induced corrosion in RCPB Components (PWRs Only)" 

 47 PWR Stainless steel, nickel 

alloy control rod drive head penetration pressure housing exposed to reactor coolant 

Cracking due to stress corrosion cracking, primary water stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD," and AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-55 

 48 PWR Steel external surfaces: 

reactor vessel top head, reactor vessel bottom head, reactor coolant pressure boundary piping or components adjacent to dissimilar metal (Alloy 82/182) welds exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion," and AMP XI.M11B, "Cracking of NickelAlloy Components and Loss of Material Due to Boric Acid- Induced Corrosion in RCPB Components (PWRs Only)" 

No IV.A2.RP379 

IV.C2.RP380 

M 49 PWR Steel reactor vessel, 

piping, piping components in the reactor coolant pressure boundary of PWRs, or steel steam generators 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No IV.A2.R-17 

IV.C2.R-17 IV.C2.RP167 IV.D1.R-17 IV.D2.R-17 
3.1-40 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

in PWRs: external surfaces or closure bolting exposed to air with borated water leakage 

M 50 BWR/PWR Cast austenitic stainless 

steel Class 1 piping, piping component (including pump casings and control rod drive pressure housings) exposed to reactor coolant >250 °F (>482 °C) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)" 

No IV.A2.R-77 

IV.C1.R-52 IV.C2.R-52 

D 51a D 51b D 52a D 52b D 52c 
3.1-41 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

D 53a D 53b D 53c M 54 PWR Stainless steel bottom 

mounted instrument system flux thimble tubes (with or without chrome plating) exposed to reactor coolant and neutron flux 

Loss of material due to wear 

AMP XI.M37, "Flux Thimble Tube Inspection" 

No IV.B2.RP284 

D 55a D 55b D 55c 
3.1-42 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

D 56a D 56b D 56c D 58a D 58b D 59a D 59b D 59c 
3.1-43 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 60 BWR Steel piping, piping 

components exposed to reactor coolant 

Wall thinning due to flow-accelerated corrosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No IV.C1.R-23 

 61 PWR Steel steam generator 

steam nozzle and safe end, feedwater nozzle and safe end, AFW nozzles and safe ends exposed to secondary feedwater/steam 

Wall thinning due to flow-accelerated corrosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No IV.D1.R-37 

IV.D2.R-38 

 62 PWR High-strength, low alloy 

steel, or stainless steel closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air with reactor coolant leakage 

Cracking due to stress corrosion cracking 

AMP XI.M18, "Bolting Integrity" 

No IV.A2.R-78 

IV.C2.R-11 IV.D1.R-10 

 63 BWR Steel or stainless steel 

closure bolting exposed to air with reactor coolant leakage 

Loss of material due to general (steel only), pitting, crevice corrosion, wear 

AMP XI.M18, "Bolting Integrity" 

No IV.C1.RP-42 

 64 PWR Steel closure bolting 

exposed to air – indoor uncontrolled 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No IV.C2.RP166 

 65 PWR Stainless steel control 

rod drive head penetration flange bolting exposed to air with reactor coolant leakage 

Loss of material due to wear 

AMP XI.M18, "Bolting Integrity" 

No IV.A2.R-79 
3.1-44 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 66 PWR High-strength, low alloy 

steel, or stainless steel closure bolting; stainless steel control rod drive head penetration flange bolting exposed to air with reactor coolant leakage 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No IV.A2.R-80 

IV.C2.R-12 

 67 BWR/PWR Steel or stainless steel 

closure bolting exposed to air – indoor with potential for reactor coolant leakage 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No IV.C1.RP-43 

IV.D1.RP-46 IV.D2.RP-46 

 68 PWR Nickel alloy steam 

generator tubes exposed to secondary feedwater or steam 

Changes in dimension ("denting") due to corrosion of carbon steel tube support plate 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-43 

IV.D2.R-226 

 69 PWR Nickel alloy steam 

generator tubes and sleeves exposed to secondary feedwater or steam 

Cracking due to outer diameter stress corrosion cracking or intergranular attack 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-47 

IV.D1.R-48 IV.D2.R-47 IV.D2.R-48 

 70 PWR Nickel alloy steam 

generator tubes, repair sleeves, and tube plugs exposed to reactor coolant 

Cracking due to primary water stress corrosion cracking 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-40 

IV.D1.R-44 IV.D2.R-40 IV.D2.R-44 

 71 PWR Steel, chrome plated 

steel, stainless steel, nickel alloy steam generator U-bend supports including antivibration bars exposed 

Cracking due to stress corrosion cracking or other mechanism(s); loss of material due general (steel only), pitting, crevice corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.RP226 

IV.D1.RP384 
3.1-45 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

to secondary feedwater or steam 

 72 PWR Steel steam generator 

tube support plate, tube bundle wrapper, supports and mounting hardware exposed to secondary feedwater or steam 

Loss of material due to erosion, general, pitting, crevice corrosion, ligament cracking due to corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-42 

IV.D1.RP161 IV.D2.R-42 IV.D2.RP162 

 73 PWR Nickel alloy steam 

generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater or steam 

Loss of material due to wastage, pitting corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.R-50 

 74 PWR Steel steam generator 

upper assembly and separators including feedwater inlet ring and support exposed to secondary feedwater or steam 

Wall thinning due to flow-accelerated corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-49 

 75 PWR Steel steam generator 

tube support lattice bars exposed to secondary feedwater or steam 

Wall thinning due to flow-accelerated corrosion, general corrosion 

AMP XI.M19, "Steam Generators," and AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-48 

M 76 PWR Steel, chrome plated 

steel, stainless steel, nickel alloy steam generator U-bend supports including antiLoss of material due to wear, fretting AMP XI.M19, "Steam Generators" No IV.D1.RP- 225 
3.1-46 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

vibration bars exposed to secondary feedwater or steam 

 77 PWR Nickel alloy steam 

generator tubes and sleeves exposed to secondary feedwater or steam 

Loss of material due to wear, fretting 

AMP XI.M19, "Steam Generators" 

No IV.D1.RP233 

IV.D2.RP233 

 78 PWR Nickel alloy steam 

generator components such as, secondary side nozzles (vent, drain, and instrumentation) exposed to secondary feedwater or steam 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection," or AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." 

No IV.D2.R-36 

 79 BWR Stainless steel; steel 

with nickel-alloy or stainless steel cladding; and nickel-alloy reactor coolant pressure boundary components exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C1.RP158 

 80 PWR Stainless steel or steel 

with stainless steel cladding pressurizer relief tank: tank shell and heads, flanges, nozzles (none-ASME Section XI components) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP383 
3.1-47 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

exposed to treated borated water >60°C (>140°F) 

 81 PWR Stainless steel 

pressurizer spray head exposed to reactor coolant 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP-41 

 82 PWR Nickel alloy pressurizer 

spray head exposed to reactor coolant 

Cracking due to stress corrosion cracking, primary water stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.C2.RP-40 

 83 PWR Steel steam generator 

shell assembly exposed to secondary feedwater or steam 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.D1.RP372 

IV.D2.RP153 

 84 BWR Steel top head 

enclosure (without cladding) top head nozzles (vent, top head spray or RCIC, and spare) exposed to reactor coolant 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.A1.RP-50 

 85 BWR Stainless steel, nickel 

alloy, and steel with nickel alloy or stainless steel cladding reactor vessel flanges, nozzles, penetrations, safe ends, vessel shells, heads and welds exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No IV.A1.RP157 
3.1-48 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 86 PWR Stainless steel steam 

generator primary side divider plate exposed to reactor coolant 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry" 

No IV.D1.RP-17 

 87 PWR Stainless steel, nickel 

alloy PWR reactor internal components exposed to reactor coolant, neutron flux 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry" 

No IV.B2.RP-24 

IV.B3.RP-24 IV.B4.RP-24 

 88 PWR Stainless steel; steel 

with nickel-alloy or stainless steel cladding; and nickel-alloy reactor coolant pressure boundary components exposed to reactor coolant 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry" 

No IV.A2.RP-28 

IV.C2.RP-23 

M 89 PWR Steel piping, piping 

components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No IV.C2.RP221 

M 90 PWR Copper alloy piping, 

piping components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No IV.C2.RP222 

M 91 BWR Steel reactor vessel 

closure flange assembly components (including flanges, nut, studs, and washers) exposed to air with potential for reactor coolant leakage 

Cracking due to stress corrosion cracking; loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M3, "Reactor Head Closure Stud Bolting" 

No IV.A1.RP165 

IV.A1.RP-51 
3.1-49 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 92 PWR Steel reactor vessel 

closure flange assembly components (including flanges, nut, studs, and washers) exposed to air with potential for reactor coolant leakage 

Cracking due to stress corrosion cracking; loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M3, "Reactor Head Closure Stud Bolting" 

No IV.A2.RP-52 

IV.A2.RP-53 

M 93 PWR Copper alloy >15% Zn 

or > 8% Al piping, piping components exposed to closed-cycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No IV.C2.RP-12 

M 94 BWR Stainless steel and 

nickel alloy vessel shell attachment welds exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, cyclic loading 

AMP XI.M4, "BWR Vessel ID Attachment Welds," and AMP XI.M2, "Water Chemistry" 

No IV.A1.R-64 

 95 BWR Steel (with or without 

stainless steel cladding) feedwater nozzles exposed to reactor coolant 

Cracking due to cyclic loading 

AMP XI.M5, "BWR Feedwater Nozzle" 

No IV.A1.R-65 

M 96 BWR Steel (with or without 

stainless steel cladding) control rod drive return line nozzles and their nozzle-to-vessel welds exposed to reactor coolant in BWR-3, BWR-4, BWR-5, and BWR-6 designs 

Cracking due to cyclic loading, stress corrosion cracking, or intergranular stress corrosion cracking 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.A1.R-66 
3.1-50 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 97 BWR Stainless steel and 

nickel alloy piping, piping components greater than or equal to 4 NPS; nozzle safe ends and associated welds; control rod drive return line nozzle cap and associated cap-tonozzle weld or cap-tosafe end weld in BWR-3, BWR 4, BWR 5, and BWR-6 designs 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.17) 

IV.A1.R-412 IV.C1.R-20 IV.C1.R-21 

 98 BWR Stainless steel, nickel 

alloy penetrations: instrumentation and standby liquid control exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, cyclic loading 

AMP XI.M8, "BWR Penetrations," and AMP XI.M2, "Water Chemistry" 

No IV.A1.RP369 

M 99 BWR Stainless steel (including 

cast austenitic stainless steel; PH martensitic stainless steel; martensitic stainless steel); nickel alloy (including X-750 alloy) reactor internal components exposed to reactor coolant and neutron flux 

Loss of fracture toughness due to thermal aging, neutron irradiation embrittlement 

AMP XI.M9, "BWR Vessel Internals" 

Yes (SRP-SLR Section 3.1.2.2.13) 

IV.B1.RP182 IV.B1.RP200 IV.B1.RP219 IV.B1.RP220 IV.B1.R-416 IV.B1.R-417 IV.B1.R-419 
3.1-51 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 100 BWR Stainless steel reactor 

vessel internals components (jet pump wedge surface) exposed to reactor coolant 

Loss of material due to wear 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.RP377 

M 101 BWR Stainless steel steam 

dryers exposed to reactor coolant 

Cracking due to flowinduced vibration, stress corrosion cracking, intergranular stress corrosion cracking; loss of material due to wear 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.RP155 

 102 BWR Stainless steel fuel 

supports and control rod drive assemblies control rod drive housing exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

No IV.B1.R-104 

M 103 BWR Stainless steel and 

nickel alloy reactor internal components exposed to reactor coolant and neutron flux 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, irradiation-assisted stress corrosion cracking 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.1.2.2.12.1) 

IV.B1.R-422 IV.B1.R-100 IV.B1.R-105 IV.B1.R-92 IV.B1.R-93 IV.B1.R-96 IV.B1.R-97 IV.B1.R-98 IV.B1.R-99 

M 104 BWR Nickel alloy reactor 

vessel internal components exposed to reactor coolant and neutron flux 

Cracking due to intergranular stress corrosion cracking 

AMP XI.M9, "BWR Vessel Internals," and AMP XI.M2, "Water Chemistry" 

No IV.B1.RP381 
3.1-52 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 105 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.1.2.2.18) 

IV.E.RP-353 

M 106 BWR/PWR Nickel alloy piping, 

piping components and piping element exposed to air – indoor uncontrolled, or air with borated water leakage 

None None No IV.E.RP-03 

IV.E.RP-378 

M 107 BWR/PWR Stainless steel piping, 

piping components exposed to gas, air with borated water leakage, air – indoors, uncontrolled 

None None No IV.E.RP-04 

IV.E.RP-05 IV.E.RP-07 

M 110 BWR Any material piping, 

piping components exposed to reactor coolant 

Wall thinning due to erosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No IV.C1.R-406 

N 111 PWR Nickel alloy steam 

generator tubes exposed to secondary feedwater or steam 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M19, "Steam Generators" 

No IV.D1.R-407 

IV.D2.R-407 

N 113 BWR Steel reactor vessel 

external attachments exposed to indoor, uncontrolled air 

Loss of material due to general, pitting, crevice corrosion, wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and AMP XI.M2, "Water Chemistry," for chemistry or corrosionrelated aging effect 

No IV.A1.R-409 
3.1-53 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

mechanisms 

N 114 BWR/PWR Reactor coolant system 

components defined as ASME Section XI Code Class components (ASME Code Class 1 reactor coolant pressure boundary components or core support structure components, or ASME Class 2 or 3 components - including ASME defined appurtenances, component supports, and associated pressure boundary welds, or components subject to plant-specific equivalent classifications for these ASME code classes) 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking (stainless steel, nickel alloy components only), cyclical loading; loss of material due to general corrosion (steel only), pitting corrosion, crevice corrosion, wear 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No IV.E.R-444 

N 115 BWR/PWR Stainless steel piping, 

piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.1.2.2.18) 

IV.E.RP-06 

N 116 PWR Nickel alloy control rod 

drive penetration nozzles exposed to reactor coolant 

Loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.10.1) 

IV.A2.R-413 
3.1-54 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 117 PWR Stainless steel, nickel 

alloy control rod drive penetration nozzle thermal sleeves exposed to reactor coolant 

Loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.10.2) 

IV.A2.R-414 

N 118 PWR Stainless steel, nickel 

alloy PWR reactor vessel internal components exposed to reactor coolant, neutron flux 

Cracking due to stress corrosion cracking, irradiation-assisted stress corrosion cracking, cyclical loading, fatigue 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.R-423 IV.B3.R-423 IV.B4.R-423 

N 119 PWR Stainless steel, nickel 

alloy PWR reactor vessel internal components exposed to reactor coolant, neutron flux 

Loss of fracture toughness due to neutron irradiation embrittlement or thermal aging embrittlement; changes in dimensions due to void swelling or distortion; loss of preload due to thermal and irradiation enhanced stress relaxation or creep; loss of material due to wear 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.9) 

IV.B2.R-424 IV.B3.R-424 IV.B4.R-424 

N 120 BWR Stainless steel core 

plate rim holddown bolts exposed to reactor coolant and neutron flux 

Loss of preload due to thermal or irradiationenhanced stress relaxation 

AMP XI.M9, "BWR Vessel Internals," and TLAA SRP-SLR 4.7 "Other Plant-Specific TLAAs" (if an analysis is performed as part of the aging management basis 

Yes (only if a TLAA exists for the CLB) (SRPSLR Section 3.1.2.2.14) 

IV.B1.R-420 
3.1-55 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

and conforms to the definition of a TLAA in 10 CFR 54.3(a)) 

N 121 BWR Stainless steel jet pump 

assembly holddown beam bolts exposed to reactor coolant and neutron flux 

Loss of preload due to thermal or irradiationenhanced stress relaxation 

AMP XI.M9, "BWR Vessel Internals" 

No IV.B1.R-421 

N 122 BWR/PWR Steel, stainless steel, 

nickel alloy, copper alloy Non-ASME Code Class 1 piping, piping components exposed to air – indoor, condensation 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No IV.C1.R-429 

IV.C2.R-429 

N 124 BWR/PWR Steel, stainless steel, 

nickel alloy, copper alloy piping, piping components exposed to condensation 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No IV.C1.R-431 

IV.C2.R-431 

N 125 PWR Nickel alloy steam 

generator tubes at support plate locations exposed to secondary feedwater or steam 

Cracking due to flowinduced vibration or high-cycle fatigue 

AMP XI.M2, "Water Chemistry," and AMP XI.M19, "Steam Generators" 

No IV.D1.R-437 

IV.D2.R-442 

N 127 PWR Steel (with stainless 

steel or nickel alloy cladding) steam generator heads exposed to reactor coolant 

Loss of material due to boric acid corrosion 

AMP XI.M2, "Water Chemistry," and plantspecific aging management program 

Yes (SRP-SLR Section 3.1.2.2.15) 

IV.D1.R-436 IV.D2.R-440 
3.1-56 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 128 BWR Stainless steel, nickel 

alloy nozzles safe ends and welds: high pressure core spray; low pressure core spray; recirculating water, low pressure coolant injection or RHR injection mode exposed to reactor coolant 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

No IV.A1.R-68 

N 129 BWR Steel and stainless steel 

piping, piping components exposed to reactor coolant: welded connections between the re-routed control rod drive return line and the inlet piping system that delivers return line flow to the reactor pressure vessel exposed to reactor coolant 

Cracking due to cyclic loading 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.16.1) 

IV.C1.R-432 

N 130 BWR Steel (with or without 

stainless steel cladding) control rod drive return line nozzles and their nozzle-to-vessel welds exposed to reactor coolant in BWR-2 designs 

Cracking due to cyclic loading 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.1.2.2.16.2) 

IV.A1.R-411 
3.1-57 

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in 

Chapter IV of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 133 BWR/PWR Steel components 

exposed to reactor coolant or treated water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "OneTime Inspection" No IV.A1.R-448 IV.C1.R-448 

IV.C2.R-448 IV.D1.R-448 IV.D2.R-448 

N 134 BWR/PWR Jacketed thermal 

insulation in air-indoor uncontrolled, air with borated water leakage, air with reactor coolant leakage, or air with steam or feedwater leakage 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No IV.A1.R-450 

IV.A2.R-450 IV.C1.R-450 IV.C2.R-450 IV.D1.R-450 IV.D2.R-450 
3.1-58 

Table 3.1-2. Aging Management Programs and Additional Guidance Appendices 

Recommended for Reactor Vessel, Internals, and Reactor Coolant System 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP X.M1 Cyclic Load Monitoring 

AMP XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD 

AMP XI.M2 Water Chemistry 

AMP XI.M3 Reactor Head Closure Stud Bolting 

AMP XI.M4 Boiling Water Reactor Vessel ID Attachment Welds 

AMP XI.M5 Boiling Water Reactor Feedwater Nozzle 

AMP XI.M6 Deleted 

AMP XI.M7 Boiling Water Reactor Stress Corrosion Cracking 

AMP XI.M8 Boiling Water Reactor Penetrations 

AMP XI.M9 Boiling Water Reactor Vessel Internals 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M11B Cracking of Nickel-Alloy Components and Loss of Material 

Due to Boric Acid-induced Corrosion in Reactor Coolant 

Pressure Boundary Components (PWRs only) 

AMP XI.M12 Thermal Aging of Cast Austenitic Stainless Steel (CASS) 

AMP XI.M16A Deleted 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M19 Steam Generators 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M31 Reactor Vessel Surveillance 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M35 ASME Code Class 1 Small Bore-Piping 

AMP XI.M37 Flux Thimble Tube Inspection 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 
3.2-1 

1 3.2 Aging Management of Engineered Safety Features 

2 Review Responsibilities 

3 Primary—Branch assigned responsibility by Project Manager (PM) as described in Standard 

4 Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

5 (SRP-SLR) Section 3.0 of this SRP-SLR Report. 

6 3.2.1 Areas of Review 

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

8 management programs (AMP) of the engineered safety features. For a recent vintage plant, the 

9 information related to the engineered safety features is contained in Chapter 6, “Engineered 

10 Safety Features,” of the plant’s Final Safety Analysis Report (FSAR), consistent with the 

11 “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants” 

12 (NUREG–0800). The engineered safety features contained in this review plan section are 

13 generally consistent with those contained in NUREG–0800 except for the refueling water, 

14 control room habitability, and residual heat removal systems. For older plants, the location of 

15 applicable information is plant-specific because an older plant’s FSAR may have predated 

16 NUREG–0800. 

17 The engineered safety features consist of containment spray, standby gas treatment 

18 [boiling water reactor (BWRs)], containment isolation components, and emergency core 

19 cooling systems. 

20 The responsible review organization is to review the following subsequent license renewal 

21 application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 3.0: 

22 AMRs 

23  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

24 License Renewal (GALL-SLR) Report 

25  AMR results for which further evaluation is recommended 

26  AMR results not consistent with or not addressed in the GALL-SLR Report 

27 AMPs 

28  Consistent with GALL-SLR Report AMPs 

29  Plant-specific AMPs 

30 FSAR Supplement 

31  The responsible review organization is to review the FSAR Supplement associated with 

32 each assigned AMP. 
3.2-2 

1 3.2.2 Acceptance Criteria 

2 The acceptance criteria for the areas of review describe methods for determining whether the 

3 applicant has met the requirements of the U.S. Nuclear Regulatory Commission’s (NRC) 

4 regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

5 3.2.2.1 AMR Results Consistent With the Generic Aging Lessons Learned for 

6 Subsequent License Renewal Report 

7 The AMR and the AMPs applicable to the engineered safety features are described and 

8 evaluated in Chapter V of the GALL-SLR Report. 

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

10 confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

11 cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item 

12 is consistent with the GALL-SLR Report AMR item to which it is compared. 

13 When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, 

14 the reviewer should confirm that the alternate AMP is valid to use for aging management and 

15 will be capable of managing the effects of aging as adequately as the AMP recommended by 

16 the GALL-SLR Report. 

17 3.2.2.2 Aging Management Review Results for Which Further Evaluation Is 

18 Recommended by the Generic Aging Lessons Learned for Subsequent License 

19 Renewal Report 

20 The basic acceptance criteria defined in Subsection 3.2.2.1 need to be applied first for all of the 

21 AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR 

22 item to which the SLRA AMR item is compared identifies that “further evaluation is 

23 recommended,” then additional criteria apply as identified by the GALL-SLR Report for each of 

24 the following aging effect/aging mechanism combinations. Refer to Table 3.2-1, comparing the 

25 “Further Evaluation Recommended” and the “GALL-SLR Item” column, for the AMR items that 

26 reference the following subsections. 

27 3.2.2.2.1 Cumulative Fatigue Damage 

28 Fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required 

29 to be evaluated in accordance with 10 CFR 54.21(c). This TLAA is addressed separately in 

30 Section 4.3, “Metal Fatigue Analysis,” of this SRP-SLR Report. 

31 3.2.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion 

32 Loss of material due to pitting and crevice corrosion could occur in SS piping, piping 

33 components, and tanks exposed to outdoor air or any air environment when the component is 

34 insulated or where the component is in the vicinity of insulated components. The possibility of 

35 pitting and crevice corrosion also extends to indoor components located in close proximity to 

36 sources of outdoor air (e.g., components near intake vents). Pitting and crevice corrosion is 

37 known to occur in environments containing sufficient halides (e.g., chlorides) and in which the 

38 presence of moisture is possible. 
3.2-3 

1 Applicable outdoor air environments (and associated local indoor air environments) include, but 

2 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

3 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

4 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

5 compounds, and areas subject to chloride contamination from other agricultural or 

6 industrial sources. 

7 Insulated SS components exposed to indoor air environments and outdoor air environments are 

8 susceptible to loss of material due to pitting or crevice corrosion if the insulation contains certain 

9 contaminants. Leakage of fluids through mechanical connections such as bolted flanges and 

10 valve packing can result in contaminants leaching onto the component surface. For outdoor 

11 insulated SS components, rain and changing weather conditions can result in moisture intrusion 

12 of the insulation. 

13 The applicant may demonstrate that loss of material due to pitting and crevice corrosion is not 

14 expected to occur by one or more of the following applicable means. 

15  For outdoor uninsulated components, describing the outdoor air environment present at 

16 the plant and demonstrating that external pitting or crevice corrosion is not expected. 

17  For underground components, the applicant may demonstrate that loss of material due 

18 to pitting or crevice corrosion due to exposure to in-leakage to the vault as a result of 

19 external precipitation or groundwater is not expected. 

20  For insulated components, determining that the insulation does not contain sufficient 

21 contaminants to cause loss of material due to pitting or crevice corrosion. One 

22 acceptable means to demonstrate this is provided by Regulatory Guide 1.36, 

23 “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

24  For indoor components, determining that there are no liquid-filled systems with threaded 

25 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

26  For all components, demonstrating that the aggressive environment is not present by 

27 isolating the component from the environment using a barrier to prevent loss of material 

28 due to pitting or crevice corrosion. An acceptable barrier includes coatings that have 

29 been demonstrated to be impermeable to aqueous solutions and atmospheric air that 

30 contain halides. If a barrier coating is credited for isolating a component from a 

31 potentially aggressive environment, then the barrier coating is evaluated to verify that it 

32 is impervious to the plant-specific environment. GALL-SLR Report AMP XI.M42, 

33 “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 

34 and Tanks,” is an acceptable method to manage the integrity of a barrier coating for 

35 internal or external coatings. 

36 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

37 to manage this aging effect based on the environmental conditions applicable to the plant and 

38 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

39 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 

40 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

41 manage loss of material due to pitting and crevice corrosion in SS piping, piping components, 

42 and tanks. 
3.2-4 

1 3.2.2.2.3 Loss of Material Due to Erosion 

2 Loss of material due to erosion could occur in the SS high-pressure safety injection (HPSI) 

3 pump minimum flow recirculation orifice exposed to treated borated water. The GALL-SLR 

4 Report recommends a plant-specific AMP be evaluated for erosion of the orifice due to 

5 extended use of the centrifugal HPSI pump for normal charging. Further evaluation is 

6 recommended to ensure that the aging effect is adequately managed. Acceptance criteria are 

7 described in Branch Technical Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

8 3.2.2.2.4 Loss of Material Due to General Corrosion and Flow Blockage Due to Fouling 

9 Loss of material due to general corrosion and flow blockage due to fouling can occur in the 

10 spray nozzles and flow orifices in the drywell and suppression chamber spray system exposed 

11 to air–indoor uncontrolled. This aging effect and mechanism will apply since the carbon steel 

12 piping upstream of the spray nozzles and flow orifices is occasionally wetted, even though the 

13 majority of the time this system is in standby. The wetting and drying of these components can 

14 accelerate corrosion in the system and lead to flow blockage from an accumulation of corrosion 

15 products. The GALL-SLR Report recommends further evaluation of a plant-specific AMP to 

16 ensure that the aging effect is adequately managed. Acceptance criteria are described in 

17 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

18 3.2.2.2.5 Cracking Due to Stress Corrosion Cracking 

19 Cracking due to SCC could occur for SS piping, piping components, and tanks exposed to 

20 outdoor air or any air environment when the component is insulated. The possibility of cracking 

21 also extends to indoor components located in close proximity to sources of outdoor air 

22 (e.g., components near intake vents). Cracking is known to occur in environments containing 

23 sufficient halides (e.g., chlorides) and in which moisture is possible. 

24 Applicable outdoor air environments (and associated local indoor air environments) include, but 

25 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

26 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

27 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

28 compounds, and areas subject to chloride contamination from other agricultural or industrial 

29 sources. 

30 Insulated SS components exposed to indoor air environments and outdoor air environments are 

31 susceptible to SCC if the insulation contains certain contaminants. Leakage of fluids through 

32 bolted connections (e.g., flanges, valve packing) can result in contaminants present in the 

33 insulation leaching onto the component surface. For outdoor insulated SS components, rain 

34 and changing weather conditions can result in moisture intrusion of the insulation. 

35 The applicant may demonstrate that SCC is not expected to occur by one or more of the 

36 following applicable means. 

37  For outdoor uninsulated components, describing the outdoor air environment present at 

38 the plant and demonstrating that SCC is not expected. 

39  For underground components, the applicant may demonstrate that SCC due to exposure 

40 to in-leakage to the vault as a result of external precipitation or groundwater is not 

41 expected. 
3.2-5 

1  For insulated components, determining that the insulation does not contain sufficient 

2 contaminants to cause SCC. One acceptable means to demonstrate this is provided by 

3 Regulatory Guide 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

4  For indoor components, determining that there are no liquid-filled systems with threaded 

5 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

6  For all components, demonstrating that the aggressive environment is not present by 

7 isolating the component from the environment using a barrier to prevent loss of material 

8 due to pitting or crevice corrosion. An acceptable barrier includes tightly-adhering 

9 coatings that have been demonstrated to be impermeable to aqueous solutions and 

10 atmospheric air that contain halides. If a barrier coating is credited for isolating a 

11 component from a potentially aggressive environment then the barrier coating is 

12 evaluated to verify that it is impervious to the plant-specific environment. GALL-SLR 

13 Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

14 Heat Exchangers, and Tanks,” is an acceptable method to manage the integrity of a 

15 barrier coating for internal or external coatings. 

16 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

17 to manage this aging effect based on the environmental conditions applicable to the plant and 

18 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

19 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 

20 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

21 manage cracking of SS due to SCC in piping, piping components, and tanks.

22 3.2.2.2.6 Quality Assurance for Aging Management of Nonsafety-Related Components 

23 Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR Report). 

24 3.2.2.2.7 Ongoing Review of Operating Experience 

25 Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

26 Management Programs.” 

27 3.2.2.2.8 Loss of Material Due to Recurring Internal Corrosion 

28 Recurring internal corrosion can result in the need to augment AMPs beyond the 

29 recommendations in the GALL-SLR Report. During the search of plant-specific operating 

30 experience conducted during the SLRA development, recurring internal corrosion can be 

31 identified by the number of occurrences of aging effects and the extent of degradation at each 

32 localized corrosion site. This further evaluation item is applicable if the search of plant-specific 

33 operating experience reveals repetitive occurrences [e.g., one per refueling outage cycle that 

34 has occurred: (a) in any three or more cycles for a 10-year operating experience search, or 

35 (b) in any two or more cycles for a 5-year operating experience search] of aging effects with the 

36 same aging mechanism in which the aging effect resulted in the component either not meeting 

37 plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 

38 50 percent (regardless of the minimum wall thickness). 

39 The GALL-SLR Report recommends that a plant-specific AMP, or a new or existing AMP, be 

40 evaluated for inclusion of augmented requirements to ensure the adequate management of any 

41 recurring aging effect(s). Potential augmented requirements include: alternative examination 

42 methods (e.g., volumetric versus external visual), augmented inspections (e.g., a greater 
3.2-6 

1 number of locations, additional locations based on risk insights based on susceptibility to aging 

2 effect and consequences of failure, a greater frequency of inspections), and additional trending 

3 parameters and decision points where increased inspections would be implemented. 

4 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report).” 

5 The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

6 recurring aging effect before affecting the ability of a component to perform its intended function, 

7 (b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

8 parameters will be trended as well as the decision points where increased inspections would be 

9 implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

10 change), (d) how inspections of components that are not easily accessed (i.e., buried, 

11 underground) will be conducted, and (e) how leaks in any involved buried or underground 

12 components will be identified. 

13 Plant-specific operating experience examples should be evaluated to determine if the chosen 

14 AMP should be augmented even if the thresholds for significance of aging effect or frequency of 

15 occurrence of aging effect have not been exceeded. For example, during a 10-year search of 

16 plant specific operating experience, two instances of 360 degree 30 percent wall loss occurred 

17 at copper alloy to steel joints. Neither the significance of the aging effect nor the frequency of 

18 occurrence of aging effect threshold has been exceeded. Nevertheless, the operating 

19 experience should be evaluated to determine if the AMP that is proposed to manage the aging 

20 effect is sufficient (e.g., method of inspection, frequency of inspection, number of inspections) to 

21 provide reasonable assurance that the current licensing basis (CLB) intended functions of the 

22 component will be met throughout the subsequent period of extended operation. Likewise, the 

23 GALL-SLR Report AMR items associated with the new further evaluation items only cite raw 

24 water and waste water environments because operating experience indicates that these are the 

25 predominant environments associated with recurring internal corrosion; however, if the search 

26 of plant-specific operating experience reveals recurring internal corrosion in other water 

27 environments (e.g., treated water), the aging effect should be addressed in a similar manner. 

28 3.2.2.2.9 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

29 Corrosion Cracking 

30 Cracking due to SCC and intergranular stress corrosion cracking (IGSCC) could occur in BWR 

31 SS and nickel alloy piping and piping components greater than or equal to 4 inches nominal 

32 pipe size (NPS); nozzle safe ends and associated welds; and control rod drive return line nozzle 

33 caps and the associated cap-to-nozzle welds or cap-to-safe end welds in BWR-3, BWR-4, 

34 BWR-5, and BWR-6 designs that are exposed to reactor coolant. The GALL-SLR Report 

35 recommends GALL-SLR Report AMP XI.M2, “Water Chemistry,” to mitigate SCC and IGSCC 

36 and augmented inspection activities in accordance with GALL-SLR Report AMP XI.M7, “BWR 

37 Stress Corrosion Cracking,” for condition monitoring. However, these programs may need to be 

38 augmented to manage the effects of cracking in dead-legs and other piping locations with 

39 stagnant flow where localized environmental conditions could exacerbate the mechanisms of 

40 SCC and IGSCC. The GALL-SLR Report recommends further evaluation to identify any such 

41 locations and to evaluate the adequacy of the applicant’s proposed AMPs on a case-by-case 

42 basis to ensure that the intended functions of components in these locations will be maintained 

43 during the subsequent period of extended operation. Acceptance criteria are described in 

44 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 
3.2-7 

1 3.2.2.2.10 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

2 SCC is a form of environmentally assisted cracking which is known to occur in high and 

3 moderate strength aluminum alloys. The three conditions necessary for SCC to occur in a 

4 component are a sustained tensile stress, aggressive environment, and material with a 

5 susceptible microstructure. The aging effect of cracking due to SCC can be mitigated by 

6 eliminating one of the three necessary conditions. For the purposes of subsequent license 

7 renewal (SLR), acceptance criteria for this further evaluation is being provided for demonstrating 

8 that the specific material is not susceptible to SCC or an aggressive environment is not present. 

9 The susceptibility of the material is to be established prior to evaluating the environment. This 

10 further evaluation item is applicable unless it is demonstrated by the applicant that one of the 

11 two necessary conditions discussed below is absent. 

12 Susceptible Material: If the material that a component is constructed of is not susceptible to 

13 SCC then the aging effect is not applicable. The microstructure of an aluminum alloy, of which 

14 alloy composition is only one factor, is what determines if the alloy is susceptible to SCC. 

15 Therefore, providing guidance based on alloy composition will not always successfully protect 

16 against SCC in aluminum alloys. The temper, condition, and product form of the alloy is 

17 considered when assessing if a material is susceptible to SCC. Aluminum alloys that are 

18 susceptible to SCC include: 

19  2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

20  5xxx series alloys with a magnesium content of 3.5 weight percent or greater 

21  6xxx series alloys in the F temper 

22  7xxx series alloys in the F, T5x, or T6x temper 

23  2xx.x and 7xx.x series alloys 

24  3xx.x series alloys that contain copper 

25  5xx.x series alloys with a magnesium content of greater than 8 weight percent 

26 The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

27 make the determination is technically substantiated. Tempers have been specifically developed 

28 to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 

29 combination which are not susceptible to SCC when used in piping, piping component, and tank 

30 applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. 

31 GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” is an acceptable method to 

32 manage cracking of aluminum due to SCC in tanks. GALL-SLR Report AMP XI.M36, “External 

33 Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage cracking 

34 of aluminum due to SCC in piping and piping components. GALL-SLR Report AMP XI.M41, 

35 “Buried and Underground Piping and Tanks,” is an acceptable method to manage cracking of 

36 aluminum due to SCC in piping and tanks which are buried or underground. GALL-SLR Report 

37 AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

38 Components” is an acceptable method to manage cracking of aluminum due to SCC in 

39 components that are not included in other AMPs. Additional acceptance criteria are described 

40 in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

41 Aggressive Environment: If the environment that an aluminum alloy is exposed to is not 

42 aggressive, such as dry gas, controlled indoor air, or treated water, then cracking due to SCC 

43 will not occur and the aging effect is not applicable. Aggressive environments that are known to 

44 result in cracking of susceptible aluminum alloys due to SCC are aqueous solutions and 

45 atmospheric air that contain halides (e.g., chloride). Halide concentrations should generally be 
3.2-8 

1 considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated 

2 aqueous solutions and atmospheric air, such as outdoor air, raw water, waste water, and 

3 condensation, unless demonstrated otherwise. If an aluminum component is encapsulated in a 

4 secondary material, such as insulation or concrete, the composition of the encapsulating 

5 material is evaluated for halides. The environment that the aluminum alloy is exposed to is 

6 evaluated to verify that it is either controlled or treated and free of halides. 

7 An alternative strategy to demonstrating that an aggressive environment is not present is to 

8 isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

9 barriers include tightly adhering coatings that have been demonstrated to be impermeable to 

10 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

11 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

12 evaluated to verify that it is impervious to the plant-specific environment. GALL-SLR Report 

13 AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

14 Exchangers, and Tanks,” or equivalent program is an acceptable method to manage the 

15 integrity of a barrier coating. 

16 3.2.2.2.11 Loss of Material Due to General, Crevice or Pitting Corrosion and 

17 Microbiologically-Induced Corrosion and Cracking Due to Stress 

18 Corrosion Cracking 

19 Loss of material due to general (steel only), crevice, or pitting corrosion and microbiologically20 induced corrosion and cracking due to SCC (SS only) can occur in steel and SS piping and 

21 piping components exposed to concrete. Concrete provides a high alkalinity environment that 

22 can mitigate the effects of loss of material for steel piping, thereby significantly reducing the 

23 corrosion rate. However, if water intrudes through the concrete, the pH can be reduced and 

24 ions that promote loss of material such as chlorides, which can penetrate the protective oxide 

25 layer created in the high alkalinity environment, can reach the surface of the metal. Carbonation 

26 can reduce the pH within concrete. The rate of carbonation is reduced by using concrete with a 

27 low water-to-cement ratio and low permeability. Concrete with low permeability also reduces 

28 the potential for the penetration of water. Adequate air entrainment improves the ability of the 

29 concrete to resist freezing and thawing cycles and therefore reduces the potential for cracking 

30 and intrusion of water. Intrusion of water can also bring bacteria to the surface of the metal, 

31 potentially resulting in microbiologically-induced corrosion in steel or SS. Cracking due to SCC, 

32 as well as pitting and crevice corrosion can occur due to halides present in the water that 

33 penetrates to the surface of the metal. 

34 If the following conditions are met, loss of material is not considered to be an applicable aging 

35 effect for steel: (a) attributes of the concrete are consistent with ACI 318 or ACI 349 

36 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in 

37 NUREG–1557; (b) plant-specific operating experience indicates no degradation of the concrete 

38 that could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

39 exposed to groundwater. For SS components loss of material and cracking due to SCC are not 

40 considered to be applicable aging effects as long as the piping is not potentially exposed to 

41 groundwater. Where these conditions are not met, loss of material due to general (steel only), 

42 crevice or pitting corrosion and microbiologically-induced corrosion and cracking due to SCC 

43 (SS only) are identified as applicable aging effects. GALL-SLR Report AMP XI.M41, “Buried 

44 and Underground Piping and Tanks,” is an acceptable method to manage these aging effects. 
3.2-9 

1 3.2.2.2.12 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically2 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

3 Water, or Sodium Pentaborate Solution 

4 Loss of material due to crevice corrosion can occur in steel with SS cladding, SS, and nickel 

5 alloy piping, piping components, heat exchanger components, spent fuel storage racks, tanks, 

6 and PWR heat exchanger components exposed to treated water, treated borated water, or 

7 sodium pentaborate solution if oxygen levels are greater than 100 ppb. In addition, loss of 

8 material due to pitting can occur if oxygen levels are greater than 100 ppb, halides or sulfates 

9 levels are greater than 150 ppb, and stagnant flow conditions exist. Loss of material due to 

10 microbiologically-induced corrosion can occur with steel with SS cladding, SS, and nickel alloy 

11 piping, piping components, heat exchanger components, spent fuel storage racks, tanks, and 

12 PWR heat exchanger components exposed to treated water, treated borated water, or sodium 

13 pentaborate solution if the pH is less than 10.5 and temperature is less than 99 °C [210 °F]. 

14 Where oxygen levels are less than or equal to 100 ppb, GALL-SLR Report AMP XI.M2, “Water 

15 Chemistry,” and GALL-SLR Report AMP XI.M32, “One-Time Inspection,” are acceptable 

16 methods to manage loss of material due to pitting and crevice corrosion. Where oxygen levels 

17 are greater than 100 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR 

18 Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

19 Components,” are acceptable methods to manage loss of material due to crevice corrosion. 

20 Where stagnant flow conditions exist, and oxygen levels are greater than 100 ppb and halides 

21 or sulfates levels are greater than 150 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” 

22 and GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

23 and Ducting Components,” are acceptable methods to manage loss of material due to pitting 

24 and crevice corrosion. 

25 Where the pH is greater than or equal to 10.5 and the temperature is greater than or equal to 

26 99 °C [210°F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR Report 

27 AMP XI.M32, “One-Time Inspection,” are acceptable methods to manage loss of material due to 

28 loss of material due to microbiologically-induced corrosion. Where the pH is less than 10.5 and 

29 temperature is less than 99 °C [210°F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and 

30 GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

31 Ducting Components,” are acceptable methods to manage loss of material due to 

32 microbiologically-induced corrosion. 

33 3.2.2.2.13 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

34 Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

35 components, and tanks exposed to an air environment for a sufficient duration of time. Air 

36 environments known to result in pitting and/or crevice corrosion of aluminum alloys are those 

37 that contain halides (e.g., chloride) and periodic moisture. The moisture level and halide 

38 concentration in atmospheric and uncontrolled air are greatly dependent on geographical 

39 location and site-specific conditions. Moisture level and halide concentration should generally 

40 be considered high enough to facilitate pitting and/or crevice corrosion of aluminum alloys in 

41 atmospheric and uncontrolled air, unless demonstrated otherwise. The periodic introduction of 

42 moisture or halides into an air environment from secondary sources should also be considered. 

43 Leakage of fluids from mechanical connections, such as bolted flanges and valve packing, 

44 through insulation onto a component in indoor controlled air is an example of a secondary 

45 source that should be considered. The operating experience (OE) and condition of aluminum 

46 alloy components are evaluated to determine if the plant-specific air environment is aggressive 
3.2-10 

1 enough to result in pitting and crevice corrosion after prolonged exposure. The aging effect of 

2 loss of material due to pitting and crevice corrosion in aluminum alloys is not applicable and 

3 does not require management if: (a) the plant-specific OE does not reveal a history of pitting or 

4 crevice corrosion and (b) a one-time inspection demonstrates that the aging effect is not 

5 occurring or that loss of material due to pitting or crevice corrosion is occurring so slowly that it 

6 will not affect the intended function of the components. 

7 The internal surfaces of aluminum components do not need to be inspected if: (a) the review of 

8 OE does not reveal a history of pitting or crevice corrosion; and (b) inspection results for 

9 external surfaces demonstrate that the aging effect is not applicable. Inspection results 

10 associated with the periodic introduction of moisture or halides from secondary sources may be 

11 treated as a separate population of components. In the environment of air-indoor controlled, 

12 pitting and crevice corrosion is only expected to occur as the result of secondary source of 

13 moisture or halides. Alloy susceptibility may be considered when reviewing OE and interpreting 

14 inspection results. Inspections focus on the most susceptible alloys and locations. 

15 The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

16 components, and tanks exposed to an air environment to determine whether an AMP is needed 

17 to manage the aging effect of loss of material due to pitting and crevice corrosion. GALL-SLR 

18 Report AMP XI.M32, “One-Time Inspection,” is an acceptable method to demonstrate that the 

19 aging effect of loss of material due to pitting and crevice corrosion is not occurring at a rate that 

20 affects the intended function of the components. If loss of material due to pitting or crevice 

21 corrosion has occurred and is sufficient to potentially affect the intended function of an 

22 aluminum SSC, the following AMPs are acceptable methods to manage loss of material due to 

23 pitting or crevice corrosion: (i) GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” 

24 for tanks; (ii) GALL-SLR Report AMP XI.M36, "External Surfaces Monitoring of Mechanical 

25 Components,” for external surfaces of piping and piping components; (iii) GALL-SLR Report 

26 AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground piping, piping 

27 components and tanks; and (iv) GALL-SLR Report Chapter XI.M38, "Inspection of Internal 

28 Surfaces in Miscellaneous Piping and Ducting Components” for internal surfaces of components 

29 that are not included in other aging management programs. 

30 3.2.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

31 Generic Aging Lessons Learned for Subsequent License Renewal Report 

32 Acceptance criteria are described in BTP RSLB-1 (Appendix A.1 of this SRP-SLR). 

33 3.2.2.4 Aging Management Programs 

34 For those AMPs that will be used for aging management and are based on the program 

35 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

36 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

37 GALL-SLR Report, Chapters X and XI. 

38 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

39 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

40 10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

41 AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

42 SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

43 Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, 
3.2-11 

1 the difference should be reviewed and properly dispositioned. The reviewer should document 

2 the disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

3 The SLRA should identify any enhancements that are needed to permit an existing AMP to be 

4 declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. The 

5 reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

6 plant AMP to be consistent with the GALL-SLR Report AMP and also that the applicant has a 

7 commitment in the FSAR Supplement to implement the enhancement prior to the subsequent 

8 period of extended operation. The reviewer should review and document the disposition of 

9 all enhancements. 

10 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

11 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

12 (Appendix A.1.2.3 of this SRP-SLR Report). 

13 3.2.2.5 Final Safety Analysis Report Supplement 

14 The summary description of the programs and activities for managing the effects of aging for the 

15 subsequent period of extended operation in the FSAR Supplement should be sufficiently 

16 comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

17 should contain information associated with the bases for determining that aging effects will be 

18 managed during the subsequent period of extended operation. The description should also 

19 contain any future aging management activities, including enhancements and commitments, to 

20 be completed before the subsequent period of extended operation. Table 3.0-1 of this 

21 SRP SLR Report provides examples of the type of information to be included in the FSAR 

22 Supplement. Table 3.2-2 lists the programs that are applicable for this SRP-SLR subsection. 

23 3.2.3 Review Procedures 

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

25 3.2.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

26 Learned for Subsequent License Renewal Report 

27 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

28 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

29 approved in the GALL-SLR Report. The reviewer should not conduct a re-review of the 

30 substance of the matters described in the GALL-SLR Report. If the applicant has provided the 

31 information necessary to adopt the finding of program acceptability as described and evaluated 

32 in the GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to the 

33 GALL-SLR Report in its SLRA. In making this determination, the reviewer confirms that the 

34 applicant has provided a brief description of the system, components, materials, and 

35 environment. The reviewer also confirms that the applicable aging effects have been addressed 

36 based on the NRC staff’s review of industry and plant-specific operating experience. 

37 Furthermore, the reviewer should confirm that the applicant has addressed operating 

38 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

39 requires the reviewer to confirm that the applicant has identified those aging effects for the 

40 engineered safety features system components that are contained in the GALL-SLR Report as 

41 applicable to its plant.
3.2-12 

1 3.2.3.2 Aging Management Review Results for Which Further Evaluation Is 

2 Recommended by the Generic Aging Lessons Learned for Subsequent License 

3 Renewal Report 

4 The basic review procedures defined in Subsection 3.2.3.1 need to be applied first to all of the 

5 AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to 

6 which the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

7 additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

8 effect/aging mechanism combinations. 

9 3.2.3.2.1 Cumulative Fatigue Damage 

10 Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

11 accordance with 10 CFR 54.21(c). The NRC staff reviews the evaluation of this TLAA 

12 separately, following the guidance in Section 4.3 of this SRP-SLR. 

13 3.2.3.2.2 Loss of Material Due to Pitting and Crevice Corrosion 

14 The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

15 and crevice corrosion of SS piping, piping components, and tanks exposed to outdoor air or any 

16 air environment when the component is insulated where the presence of sufficient halides 

17 (e.g., chlorides) and moisture is possible. The possibility of pitting and crevice corrosion 

18 also extends to indoor components located in close proximity to sources of outdoor air 

19 (e.g., components near intake vents). 

20 If the applicant claims that neither the environment nor composition of the insulation will result in 

21 loss of material due to pitting and crevice corrosion, the reviewer should evaluate the applicant’s 

22 data to verify that sufficient halides will not be present on the surface of the SS piping, piping 

23 components, or tanks. If the applicant elects to manage loss of material due to pitting or crevice 

24 corrosion, the reviewer should determine whether an adequate program is credited to manage 

25 the aging effect based on the applicable environmental conditions. 

26 3.2.3.2.3 Loss of Material Due to Erosion 

27 The GALL-SLR Report recommends further evaluation of programs to manage loss of material 

28 due to erosion of the SS high pressure safety injection pump minimum flow orifice. The 

29 reviewer reviews the applicant’s proposed program on a case-by-case basis to ensure that an 

30 adequate program will be in place to manage this aging effect. 

31 3.2.3.2.4 Loss of Material Due to General Corrosion and Flow Blockage Due to Fouling 

32 The GALL-SLR Report recommends further evaluation of programs to manage loss of material 

33 due to general corrosion and flow blockage due to fouling in the spray nozzles and flow orifices 

34 of the drywell and suppression chamber spray system spray exposed to air—indoor 

35 uncontrolled. This is necessary to prevent the plugging of spray nozzles and flow orifices of the 

36 BWR drywell and suppression chamber spray system. The reviewer reviews the applicant’s 

37 proposed program on a case-by-case basis to ensure that an adequate program will be in place 

38 for the management of loss of material due to general corrosion and flow blockage due to 

39 fouling of these components. 
3.2-13 

1 3.2.3.2.5 Cracking Due to Stress Corrosion Cracking 

2 The GALL-SLR Report recommends further evaluation to manage cracking due to SCC of SS 

3 and aluminum piping, piping components, and tanks exposed to outdoor air environments 

4 containing sufficient halides (e.g., chlorides) and in which condensation is possible. The 

5 possibility of cracking also extends to components exposed to air which has recently been 

6 introduced into buildings (i.e., components near intake vents.) 

7 If the applicant claims that neither the environment nor composition of insulation will result in 

8 stress corrosion cracking, the reviewer should evaluate the applicant’s data to verify that 

9 sufficient halides will not be present on the surface of the SS piping, piping components, or 

10 tanks. If the applicant elects to manage stress corrosion cracking, the reviewer should 

11 determine whether an adequate program is credited to manage the aging effect based on the 

12 applicable environmental conditions. 

13 3.2.3.2.6 Quality Assurance for Aging Management of Nonsafety-Related Components 

14 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

15 confirmation process, and administrative controls. Safety-related components are covered by 

16 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

17 Appendix B does not apply to nonsafety-related components that are subject to an AMR for 

18 SLR. Nevertheless, the applicant has the option to expand the scope of its 10 CFR Part 50, 

19 Appendix B program to include these components and address the associated program 

20 elements. If the applicant chooses this option, the reviewer verifies that the applicant has 

21 documented such a commitment in the FSAR Supplement. If the applicant chooses alternative 

22 means, the branch responsible for quality assurance (QA) should be requested to review the 

23 applicant’s proposal on a case-by-case basis. 

24 3.2.3.2.7 Ongoing Review of Operating Experience 

25 The applicant’s AMPs should contain the element of operating experience. The reviewer 

26 verifies that the applicant has appropriate programs or processes for the ongoing review of both 

27 plant-specific and industry operating experience concerning age-related degradation and aging 

28 management. Such reviews are used to ensure that the AMPs are effective to manage the 

29 aging effects for which they are created. The AMPs are either enhanced or new AMPs are 

30 developed, as appropriate, when it is determined through the evaluation of operating experience 

31 that the effects of aging may not be adequately managed. Additional information is in 

32 Appendix A.4, “Operating Experience for AMPs.” 

33 3.2.3.2.8 Loss of Material Due to Recurring Internal Corrosion 

34 The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

35 aging effects. The reviewer conducts an independent review of plant-specific operating 

36 experience to determine whether the plant is currently experiencing recurring internal corrosion. 

37 The scope of this further evaluation AMR item includes recurring aging effects in which the 

38 plant-specific operating experience review reveals repetitive occurrences (e.g., one per refueling 

39 outage that has occurred over: (a) three or more sequential or nonsequential cycles for a 

40 10-year operating experience search, or (b) two or more sequential or nonsequential cycles for 

41 a 5-year operating experience search) of aging effects with the same aging mechanism as a 

42 result of which the component either did not meet plant-specific acceptance criteria or 

43 experienced a reduction in wall thickness greater than 50 percent (regardless of the minimum 

44 wall thickness). 
3.2-14 

1 The reviewer should evaluate plant specific operating experience examples to determine if the 

2 chosen AMP should be augmented. For example, during a 10-year search of plant specific 

3 operating experience, two instances of 360 degree 30 percent wall loss occurred at copper alloy 

4 to steel joints. Neither the significance of the aging effect nor the frequency of occurrence of 

5 aging effect threshold has been exceeded. Nevertheless, the operating experience should be 

6 evaluated to determine if the AMP that is proposed to manage the aging effect is sufficient 

7 (e.g., method of inspection, frequency of inspection, number of inspections) to provide 

8 reasonable assurance that the CLB intended functions of the component will be met throughout 

9 the subsequent period of extended operation. Likewise, the GALL-SLR Report AMR items 

10 associated with the new further evaluation items only cite raw water and waste water 

11 environments because operating experience indicates that these are the predominant 

12 environments associated with recurring internal corrosion; however, if the search of 

13 plant-specific operating experience reveals recurring internal corrosion in other water 

14 environments (e.g., treated water), the aging effect should be addressed in a similar manner. 

15 The reviewer determines whether a proposed program is adequate to manage recurring internal 

16 corrosion by evaluating the proposed AMP against the criteria in SRP-SLR Section 3.2.2.2.8. 

17 3.2.3.2.9 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

18 Corrosion Cracking 

19 The GALL-SLR Report recommends review of plant-specific AMPs for managing cracking due 

20 to SCC and IGSCC in BWR SS and nickel alloy piping and piping components greater than or 

21 equal to 4 inches NPS; nozzle safe ends and associated welds; and control rod drive return line 

22 nozzle caps and the associated cap-to-nozzle welds or cap-to-safe end welds in BWR-3, 

23 BWR-4, BWR-5, and BWR-6 designs that are exposed to reactor coolant. Components in 

24 dead-legs and other piping locations with stagnant flow may be subject to localized 

25 environmental conditions that could exacerbate the mechanisms of SCC and IGSCC. The 

26 reviewer ensures that the applicant has identified any such locations and provided justification 

27 for the AMPs credited for managing this aging effect. The reviewer reviews the applicant’s 

28 justification and proposed AMPs on a case-by-case basis to ensure that the effects of aging will 

29 be adequately managed. 

30 3.2.3.2.10 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

31 The GALL-SLR Report recommends the further evaluation of aluminum components 

32 (i.e., piping, piping components, and tanks) exposed to atmospheric air or aqueous solutions 

33 that contain halides to manage cracking due to SCC. The reviewer must first determine if the 

34 aging effect of cracking due to SCC is applicable and requires aging management. The aging 

35 effect of cracking is to be considered applicable unless it is demonstrated that one of the two 

36 acceptance criteria are met by demonstrating that an aggressive environment is not present or 

37 the specific material is not susceptible, as discussed in Section 3.2.2.2.10. Additionally, 

38 guidance is also provided on the review of the third condition necessary for SCC to occur, a 

39 sustained tensile stress. Each of three conditions is evaluated based on the review 

40 procedures below. 

41 If the material used to fabricate the component being evaluated is not susceptible to SCC then 

42 the aging effect of cracking due to SCC is not applicable and does not require aging 

43 management. When determining if an aluminum alloy is susceptible to SCC the reviewer is to 

44 verify the material’s (a) alloy composition, (b) condition or temper, and (c) product form. 

45 Additionally, if the material was produced using a process specifically developed to provide a 
3.2-15 

1 SCC resistant microstructure then the reviewer will consider the effects of this processing in the 

2 review. Once the material information has been established the reviewer is to evaluate the 

3 technical justification used to substantiate that the material is not susceptible to SCC when 

4 exposed to an aggressive environment and sustained tensile stress. The reviewer will evaluate 

5 all documentation and references used by the applicant as part of a technical justification. 

6 If the environment that an aluminum alloy is exposed to is not aggressive, such as dry gas, 

7 controlled indoor air, or treated water, then the aging effect of cracking due to SCC is not 

8 applicable and does not require aging management. The environments cited in the AMR items 

9 in the GALL-SLR Report that reference this further evaluation are considered to be aggressive 

10 and potentially containing halide concentrations that facilitate SCC of aluminum alloys. The 

11 reviewer is to verify that components are not also periodically exposed to nontypical 

12 environments that would be categorized as aggressive, such as outdoor air which has recently 

13 been introduced into a building and the leakage/seepage of untreated aqueous solutions into a 

14 building or underground vault. Using information provided by the applicant, the reviewer will 

15 also evaluate the chemical composition of applicable encapsulating materials (e.g., concrete, 

16 insulation) for halides. 

17 If a barrier coating is employed to effectively isolate the aluminum alloy from an aggressive 

18 environment then the aging effect of cracking due to SCC is not applicable and does not require 

19 aging management. The reviewer is to verify that the barrier coating is impermeable to the 

20 plant-specific aqueous solutions and atmospheric air that the coating is intended to protect the 

21 alloy from being exposed to. If operating experience is cited as a technical justification for the 

22 effectiveness of a barrier coating the reviewer is to verify that the applicant has a program to 

23 manage loss of coating integrity equivalent to GALL-SLR Report AMP XI.M42. 

24 If the sustained tensile stress being experienced by a component is below the SCC threshold 

25 value then cracking will not occur and the aging effect is not applicable. Many aluminum alloys 

26 do not have a true SCC threshold stress, although a practical SCC threshold value can be 

27 determined based on the material, service environment, and duration of intended function. The 

28 basis for the SCC threshold value is to be evaluated to determine its applicability. The 

29 magnitude of the maximum tensile service stress (applied and residual) experienced by the 

30 component is to be evaluated to verify that the stress levels are bounded by the SCC 

31 threshold value. 

32 The information necessary to eliminate the aging effect of SCC based on the sustained service 

33 stress is often not readily available. The SCC threshold stress level is dependent on both the 

34 alloy (e.g., chemical composition, processing history, and microstructure) and service 

35 environment. Furthermore, the magnitude and state of the residual stress sustained by a 

36 component is typically not fully characterized. The reviewer must determine the adequacy of 

37 both the SCC threshold value being used by the applicant and the magnitude of the tensile 

38 stress being experienced by the component. The evaluation of the SCC threshold value 

39 includes the verification that the (a) test method used to establish the threshold value is 

40 standardized and recognized by the industry, (b) data are statistically significant or conservative, 

41 and (c) data are for a relevant alloy, temper, product form, and environment. The evaluation of 

42 the tensile stress being experienced by the component includes the verification that the stress 

43 analysis accounts for (e) all applied and residual stresses and (f) stress raiser that can initiate 

44 SCC cracks, such as corrosion pits and fabrication defects. 

45 Documentation that may assist the reviewer in determining if the aging effect of cracking due to 

46 SCC is applicable and requires aging management include (a) component drawings, 
3.2-16 

1 (b) applicable codes or specifications used in the design, fabrication, and installation of the 

2 component, (c) material-specific material certification data and lot release data, and 

3 (d) maintenance records and plant-specific operating experience. 

4 If it is determined that the aging effect of cracking due to SCC is applicable the reviewer is to 

5 evaluate the applicants proposed AMP to ensure that the effects of aging on components are 

6 adequately managed so that their intended functions will be maintained consistent with the CLB 

7 for the subsequent period of extended operation. GALL-SLR Report AMP XI.M29, 

8 “Aboveground Metallic Tanks,” is an acceptable method to manage cracking of aluminum due to 

9 SCC in tanks. GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

10 Components,” is an acceptable method to manage cracking of aluminum due to SCC in piping 

11 and piping components. GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and 

12 Tanks,” is an acceptable method to manage cracking of aluminum due to SCC in piping and 

13 tanks which are buried or underground. GALL-SLR Report AMP XI.M38, “Inspection of Internal 

14 Surfaces in Miscellaneous Piping and Ducting Components” is an acceptable method to 

15 manage cracking of aluminum due to SCC in components that are not included in other AMPs. 

16 3.2.3.2.11 Loss of Material Due to General, Crevice or Pitting Corrosion and 

17 Microbiologically-Induced Corrosion and Cracking Due to Stress 

18 Corrosion Cracking 

19 The GALL-SLR Report recommends that for steel piping and piping components exposed to 

20 concrete, if the following conditions are met, loss of material is not considered to be an 

21 applicable aging effect for steel: (a) attributes of the concrete are consistent with ACI 318 or 

22 ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in 

23 NUREG–1557; (b) plant-specific operating experience indicates no degradation of the concrete 

24 that could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

25 exposed to ground water. For SS piping and piping components, loss of material and cracking 

26 due to SCC are not considered to be applicable aging effects as long as the piping is not 

27 potentially exposed to groundwater. Where these conditions are not met, loss of material due to 

28 general (steel only), crevice or pitting corrosion and microbiologically-induced corrosion and 

29 cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

30 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

31 these aging effects. 

32 The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-to33 cement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

34 reviewer should evaluate plant-specific operating experience to determine whether concrete 

35 degradation sufficient to allow water intrusion has occurred. 

36 3.2.3.2.12 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically37 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

38 Water, or Sodium Pentaborate Solution 

39 The GALL-SLR Report recommends that loss of material due to crevice corrosion can occur in 

40 steel with SS cladding, SS, and nickel alloy piping, piping components, heat exchanger 

41 components, spent fuel storage racks, tanks, and PWR heat exchanger components exposed to 

42 treated water, treated borated water, or sodium pentaborate solution if oxygen levels are greater 

43 than 100 ppb. In addition, loss of material due to pitting can occur if oxygen levels are greater 

44 than 100 ppb, halides or sulfates levels are greater than 150 ppb, and stagnant flow conditions 

45 exist. Loss of material due to microbiologically-induced corrosion can occur with steel with SS 

46 cladding, SS, and nickel alloy piping, piping components, heat exchanger components, spent 
3.2-17 

1 fuel storage racks, tanks, and PWR heat exchanger components exposed to treated water, 

2 treated borated water, or sodium pentaborate solution if the pH is less than 10.5 and 

3 temperature is less than 99 °C [210 °F]. 

4 The reviewer verifies the applicant’s chemistry control parameters to determine whether 

5 GALL-SLR Report AMP XI.M2, “Water Chemistry,” and a one-time inspection program is 

6 implemented (e.g., GALL-SLR Report AMP XI.M32, “One-Time Inspection”) or GALL-SLR 

7 Report AMP XI.M2, “Water Chemistry,” and a periodic inspection program is implemented 

8 (e.g., GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

9 and Ducting Components”) to manage loss of material. 

10 3.2.3.2.13 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

11 The GALL-SLR Report recommends a further evaluation to determine whether an AMP is 

12 needed to manage the aging effect of loss of material due to pitting and crevice corrosion of 

13 aluminum piping, piping components, and tanks exposed to an air environment. If the applicant 

14 claims that a search of 10 years of plant-specific did not reveal any instances of loss of material 

15 due to pitting and crevice corrosion exposed to air environments, the staff conducts an 

16 independent review of plant-specific operating experience during the AMP audit. 

17 An alternative strategy to demonstrating that pitting and crevice corrosion is not applicable is to 

18 isolate the aluminum alloy from the air environment using a barrier. Acceptable barriers include 

19 anodization and tightly adhering coatings that have been demonstrated to be impermeable to 

20 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

21 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

22 evaluated to verify that it is impermeable to the plant-specific environment. GALL-SLR Report 

23 AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

24 Exchangers, and Tanks,” is an acceptable method to manage the integrity of internal and 

25 external barrier coatings. 

26 The reviewer is to verify that the SLRA cites the use of GALL-SLR AMP XI.M32, "One-Time 

27 Inspection,” for all aluminum piping, piping components, and tanks exposed to air environments. 

28 Alternatively, if the applicant states that it will utilize a strategy of isolating the aluminum 

29 components from the environment, verify that the aluminum components are coated and 

30 GALL-SLR AMP XI.M42 has been cited to manage loss of coating integrity. 

31 3.2.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

32 Generic Aging Lessons Learned for Subsequent License Renewal Report 

33 The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging 

34 effects, listed the appropriate combination of materials and environments, and AMPs that will 

35 adequately manage the aging effects. The AMP credited by the applicant could be an AMP that 

36 is described and evaluated in the GALL-SLR Report or a plant-specific program. Review 

37 procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

38 3.2.3.4 Aging Management Programs 

39 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

40 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

41 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

42 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

43 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 
3.2-18 

1 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

2 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

3 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP, with which 

4 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

5 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

6 enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

7 pertinent to the engineered safety features components are summarized in Table 3.2-1 of this 

8 SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR 

9 Report, Chapter V, presenting detailed information summarized by this row. 

10 Table 3.2-1 of this SRP-SLR may identify a plant-specific AMP. If the applicant chooses to use 

11 a plant-specific program that is not a GALL-SLR AMP, the NRC reviewer should confirm that 

12 the plant-specific program satisfies the criteria of BTP RLSB-1 (Appendix A.1.2.3 of this 

13 SRP-SLR Report). 

14 3.2.3.5 Final Safety Analysis Report Supplement 

15 The reviewer confirms that the applicant has provided in its FSAR supplement information 

16 equivalent to that in Table 3.0-1 of the applicable AMP for aging management of the engineered 

17 safety features. Table 3.2-2 lists the AMPs that are applicable for this SRP-SLR subsection. 

18 The reviewer also confirms that the applicant has provided information for Subsection 3.2.3.3, 

19 “AMR Results Not Consistent With or Not Addressed in the GALL-SLR Report,” equivalent to 

20 that in Table 3.0-1. 

21 The NRC staff expects to impose a license condition on any renewed license to require the 

22 applicant to update its FSAR to include this FSAR Supplement at the next update required 

23 pursuant to 10 CFR 50.71(e)(4). As part of the license condition until the FSAR update is 

24 complete, the applicant may make changes to the programs described in its FSAR Supplement 

25 without prior NRC approval, provided that the applicant evaluates each such change and finds it 

26 acceptable pursuant to the criteria set forth in 10 CFR 50.59. If the applicant updates the 

27 FSAR to include the final FSAR supplement before the license is renewed, no condition will 

28 be necessary. 

29 An applicant need not incorporate the implementation schedule into its FSAR. However, the 

30 reviewer should confirm that the applicant has identified and committed in the SLRA to any 

31 future aging management activities, including enhancements and commitments, to be 

32 completed before entering the subsequent period of extended operation. The NRC staff 

33 expects to impose a license condition on any renewed license to ensure that the applicant will 

34 complete these activities no later than the committed date. 

35 3.2.4 Evaluation Findings 

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

37 provisions of this section, then an evaluation finding similar to the following text should be 

38 included in the NRC staff’s safety evaluation report: 

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

40 applicant has demonstrated that the aging effects associated with the engineered 

41 safety features systems components will be adequately managed so that the 

42 intended functions will be maintained consistent with the CLB for the subsequent 

43 period of extended operation, as required by 10 CFR 54.21(a)(3). 
3.2-19 

1 The staff also reviewed the applicable FSAR Supplement program summaries 

2 and concludes that they adequately describe the AMPs credited for managing 

3 aging of the engineered safety features systems, as required by 

4 10 CFR 54.21(d). 

5 3.2.5 Implementation 

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

7 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

9 3.2.6 References 

10 1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports for 

11 Nuclear Power Plants, LWR Edition.” Washington, DC: U.S. Nuclear Regulatory 

12 Commission. March 2007. 
3.2-20 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 1 BWR/PWR Stainless steel, steel 

piping, piping components exposed to treated water, treated borated water 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.2.2.2.1) 

V.D1.E-13 V.D2.E-10 

D 2 D 3 M 4 BWR/PWR Stainless steel piping, 

piping components exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.B.EP-107 V.C.EP-107 V.D1.EP-107V.D2.EP-107 

M 5 PWR Stainless steel orifice 

(miniflow recirculation) exposed to treated borated water 

Loss of material due to erosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.3) 

V.D1.E-24 

M 6 BWR Steel drywell and 

suppression chamber spray system (internal surfaces): flow orifice; spray nozzles exposed to air – indoor uncontrolled (internal) 

Loss of material due to general corrosion; flow blockage due to fouling 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.4) 

V.D2.EP-113 

M 7 BWR/PWR Stainless steel piping, 

piping components exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical 

Yes (SRP-SLR Section 3.2.2.2.5) 

V.B.EP-103 V.C.EP-103 V.D1.EP-103V.D2.EP-103 
3.2-21 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

Components" 

M 8 PWR Aluminum, copper alloy 

(>15% Zn) piping, piping components exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No V.D1.EP-101

V.E.EP-38 

 9 PWR Steel external surfaces, 

bolting exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No V.A.E-28 

V.D1.E-28 V.E.E-28 V.E.E-41 

M 10 BWR/PWR Cast austenitic stainless 

steel piping, piping components exposed to treated borated water >250°C (>482°F), treated water >250°C (>482°F) 

Loss of fracture toughness due to thermal aging embrittlement 

AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)" 

No V.D1.E-47 

V.D2.E-11 

M 11 BWR Steel piping, piping 

components exposed to steam, treated water 

Wall thinning due to flow-accelerated corrosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No V.D2.E-07 

V.D2.E-09 

 12 BWR/PWR Steel, high-strength 

closure bolting exposed to air with steam or water leakage 

Cracking due to cyclic loading, stress corrosion cracking 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-03 

 13 BWR/PWR Steel; stainless steel 

bolting, closure bolting exposed to air – outdoor (external), air – indoor uncontrolled (external) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No V.E.EP-64 

V.E.EP-70 
3.2-22 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 14 BWR/PWR Steel closure bolting 

exposed to air with steam or water leakage 

Loss of material due to general corrosion 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-02 

M 15 BWR/PWR Copper alloy, nickel 

alloy, steel; stainless steel; bolting, closure bolting exposed to any environment, air – outdoor (external), raw water, waste water, treated borated water, fuel oil, treated water, air – indoor uncontrolled (external) 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No V.E.EP-116 

V.E.EP-117 V.E.EP-118 V.E.EP-119 V.E.EP-120 V.E.EP-121 V.E.EP-122 V.E.EP-69 

M 16 BWR/PWR Steel Containment 

isolation piping and components (Internal surfaces), Piping, piping components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.C.EP-62 

V.D2.EP-60 

M 17 BWR Aluminum, stainless 

steel piping, piping components exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC (stainless steel only) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.D2.EP-71 

V.D2.EP-73 

M 18 BWR/PWR Stainless steel 

containment isolation piping and components (internal surfaces) exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.C.EP-63 
3.2-23 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 19 BWR/PWR Stainless steel heat 

exchanger tubes exposed to treated water, treated borated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-20 

V.D2.EP-74 V.D1.E-20 

M 20 PWR Stainless steel piping, 

piping components, tanks exposed to treated borated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.E-12 

V.D1.E-12 

 21 PWR Steel (with stainless 

steel or nickel-alloy cladding) safety injection tank (accumulator) exposed to treated borated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.D1.E-38 

M 22 PWR Stainless steel piping, 

piping components, tanks exposed to treated borated water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-41 

V.D1.EP-41 

M 23 BWR/PWR Steel heat exchanger 

components, containment isolation piping, components (internal surfaces) exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No V.A.EP-90 

V.C.E-22 V.D1.EP-90 V.D2.EP-90 

M 24 PWR Stainless steel piping, 

piping components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No V.D1.EP-55 
3.2-24 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 25 BWR/PWR Stainless steel heat 

exchanger components, containment isolation piping, components (internal surfaces) exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No V.A.EP-91 

V.C.E-34 V.D1.EP-91 V.D2.EP-91 

 26 BWR Stainless steel heat 

exchanger tubes exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No V.D2.E-21 

 27 BWR/PWR Stainless steel, steel 

heat exchanger tubes exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No V.A.E-21 

V.D1.E-21 V.D2.E-23 

M 28 BWR/PWR Stainless steel piping, 

piping components exposed to closedcycle cooling water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-98 

V.C.EP-98 V.D1.EP-98 V.D2.EP-98 

M 29 BWR/PWR Steel piping, piping 

components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.C.EP-99 

M 30 BWR/PWR Steel heat exchanger 

components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-92 

V.D1.EP-92 V.D2.EP-92 

M 31 BWR/PWR Stainless steel heat 

exchanger components, piping, piping components exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-93 

V.A.EP-95 V.C.EP-95 V.D1.EP-93 V.D1.EP-95 V.D2.EP-93 
3.2-25 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

V.D2.EP-95 

M 32 BWR/PWR Copper alloy heat 

exchanger components, piping, piping components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-94 

V.A.EP-97 V.B.EP-97 V.D1.EP-94 V.D1.EP-97 V.D2.EP-94 V.D2.EP-97 

 33 BWR/PWR Copper alloy, stainless 

steel heat exchanger tubes exposed to closed-cycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No V.A.EP-100 

V.A.EP-96 V.D1.EP-96 V.D2.EP-96 

M 34 BWR/PWR Copper alloy (>15% Zn 

or >8% Al) piping, piping components, heat exchanger components exposed to closed-cycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.A.EP-27 

V.A.EP-37 V.B.EP-27 V.B.EP-37 V.D1.EP-27 V.D1.EP-37 V.D2.EP-27 V.D2.EP-37 

M 35 PWR Gray cast iron motor 

cooler exposed to Treated water, closedcycle cooling water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.A.E-43 

V.D1.E-43 

M 36 PWR Gray cast iron piping, 

piping components exposed to closed-cycle cooling water, treated water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.D1.EP-52 
3.2-26 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 37 BWR/PWR Gray cast iron piping, 

piping components exposed to soil, ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.B.EP-54 

V.D1.EP-54 V.D2.EP-54 

M 38 BWR Elastomer seals, piping, 

piping components exposed to air – indoor uncontrolled (external) 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.B.EP-59 

M 39 BWR/PWR Steel external surfaces 

exposed to condensation (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-46 

M 40 BWR/PWR Steel ducting, piping, 

components (external surfaces), ducting, closure bolting, containment isolation piping, components (external surfaces), external surfaces exposed to air – indoor uncontrolled (external) 

Loss of material due to general corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.A.E-26 

V.B.E-26 V.B.E-40 V.C.E-35 V.D2.E-26 V.E.E-44 

 41 BWR/PWR Steel external surfaces 

exposed to air – outdoor (external) 

Loss of material due to general corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-45 

M 42 BWR/PWR Aluminum piping, piping 

components exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical 

No V.E.EP-114 
3.2-27 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

Components" 

M 43 BWR Elastomer seals, piping, 

piping components exposed to air – indoor uncontrolled (internal) 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.B.EP-58 

 44 BWR/PWR Steel piping and 

components (internal surfaces), ducting and components (internal surfaces) exposed to air – indoor uncontrolled (internal) 

Loss of material due to general corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-29 

V.B.E-25 V.D2.E-29 

 45 PWR Steel encapsulation 

components exposed to air – indoor uncontrolled (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.EP-42 

 46 BWR Steel piping and 

components (internal surfaces) exposed to condensation (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.D2.E-27 

 47 PWR Steel encapsulation 

components exposed to air with borated water leakage (internal) 

Loss of material due to general, pitting, crevice, boric acid corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping 

No V.A.EP-43 
3.2-28 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

and Ducting Components" 

M 48 BWR/PWR Stainless steel piping, 

piping components (internal surfaces), tanks exposed to condensation (internal) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.EP-81 

V.D1.EP-81 V.D2.EP-61 

M 49 BWR/PWR Steel piping, piping 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-77 

V.D1.EP-77 V.D2.EP-77 

M 50 BWR/PWR Copper alloy, stainless 

steel piping, piping components exposed to lubricating oil 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-76 

V.D1.EP-76 V.D1.EP-80 V.D2.EP-76 

 51 BWR/PWR Steel, copper alloy, 

stainless steel heat exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No V.A.EP-75 

V.A.EP-78 V.A.EP-79 V.D1.EP-75 V.D1.EP-78 V.D1.EP-79 V.D2.EP-75 V.D2.EP-78 V.D2.EP-79 

M 52 BWR/PWR Steel (with coating or 

wrapping) piping, piping components exposed to soil, concrete 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.B.EP-111 
3.2-29 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 53 BWR/PWR Stainless steel, nickel 

alloy piping, piping components exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.D1.EP-72 

V.D2.EP-72 

M 53a BWR/PWR Steel, nickel alloy 

underground piping, piping components exposed to air-indoor uncontrolled, condensation, airoutdoor, raw water 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.EP-123 

M 54 BWR Stainless steel piping, 

piping components exposed to treated water >60°C (>140°F) 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.2.2.2.9) 

V.D2.E-37 

M 55 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.2.2.2.11) 

V.F.EP-112 

M 56 BWR/PWR Aluminum piping, piping 

components exposed to air – indoor uncontrolled (internal) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.13) 

V.F.EP-3 

M 57 BWR/PWR Copper alloy piping, 

piping components exposed to air – indoor uncontrolled (external), gas 

None None No V.F.EP-10 

V.F.EP-9 

M 58 PWR Copper alloy piping, 

piping components exposed to air with borated water leakage 

None None No V.F.EP-12 
3.2-30 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 59 BWR/PWR Galvanized steel 

ducting, piping, and components exposed to air – indoor controlled (external) 

None None No V.F.EP-14 

M 60 BWR/PWR Glass piping elements 

exposed to air – indoor uncontrolled (external), lubricating oil, raw water, treated water, treated borated water, air with borated water leakage, condensation (internal/external), gas, closed-cycle cooling water, air – outdoor 

None None No V.F.EP-15 

V.F.EP-16 V.F.EP-28 V.F.EP-29 V.F.EP-30 V.F.EP-65 V.F.EP-66 V.F.EP-67 V.F.EP-68 V.F.EP-87 

M 61 BWR/PWR Nickel alloy piping, 

piping components exposed to air – indoor uncontrolled (external) 

None None No V.F.EP-17 

M 62 BWR/PWR Nickel alloy piping, 

piping components exposed to air with borated water leakage 

None None No V.F.EP-115 

M 63 BWR/PWR Stainless steel piping, 

piping components exposed to air – indoor uncontrolled (external), air with borated water leakage, gas, air – indoor uncontrolled (internal) 

None None No V.F.EP-18 

V.F.EP-19 V.F.EP-22 V.F.EP-82 
3.2-31 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 64 BWR/PWR Steel piping, piping 

components exposed to air – indoor controlled (external), gas 

None None No V.F.EP-4 

V.F.EP-7 

M 65 BWR/PWR Any material piping, 

piping components exposed to treated water, treated borated water 

Wall thinning due to erosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No V.D1.E-407 

V.D2.E-408 

M 66 BWR/PWR Metallic piping, piping 

components, tanks exposed to raw water, waste water 

Loss of material due to recurring internal corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.9) 

V.A.E-400 V.B.E-400 V.C.E-400 V.D1.E-400 V.D2.E-400 

M 67 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

No V.D1.E-405 

V.D2.E-405 

M 68 BWR/PWR Steel tanks (within the 

scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete, air – outdoor, air – indoor uncontrolled, moist air, condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No V.D1.E-402 

V.D2.E-402 

M 69 BWR/PWR Insulated steel, copper 

alloy, aluminum piping, piping components, tanks exposed to condensation, air – 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-403 
3.2-32 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

outdoor 

M 70 BWR/PWR Steel, stainless steel, 

aluminum tanks (within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to treated water, treated borated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC (steel and stainless steel only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No V.A.E-404 

V.D1.E-404 V.D2.E-404 

M 71 BWR/PWR Insulated copper alloy (> 

15% Zn) piping, piping components, tanks exposed to condensation, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-406 

M 72 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, treated borated water, lubricating oil 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage, and spalling for cementitious coatings/linings 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-401 

V.B.E-401 V.C.E-401 V.D1.E-401 V.D2.E-401 

M 73 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closed-cycle cooling water, raw 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; cracking due to stress corrosion cracking 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-414 

V.B.E-414 V.C.E-414 V.D1.E-414 V.D2.E-414 
3.2-33 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

water, treated water, treated borated water, lubricating oil 

 74 BWR/PWR Gray cast iron piping 

components with internal coatings/linings exposed to closed-cycle cooling water, raw water, or treated water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No V.A.E-415 

V.B.E-415 V.C.E-415 V.D1.E-415 V.D2.E-415 

N 75 BWR/PWR Steel, stainless steel 

bolting exposed to condensation, fuel oil, lubricating oil 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-416 

V.E.E-417 

N 76 BWR/PWR Copper alloy bolting 

exposed to raw water, waste water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-418 

N 77 BWR/PWR Steel bolting exposed to 

lubricating oil, fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-419 

N 78 BWR/PWR Stainless steel, 

aluminum piping, piping components exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.A.E-420 

V.D1.E-420 V.D2.E-420 

N 79 BWR/PWR Stainless steel bolting 

exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.A.E-421 

V.D1.E-421 V.D2.E-421 

N 80 BWR/PWR Stainless steel 

underground piping, piping components, tanks exposed to air – 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.5) 

V.B.E-423 V.C.E-423 V.D1.E-423 V.D2.E-423 
3.2-34 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

outdoor 

N 81 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components exposed to air, condensation (external) 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-424 

N 83 BWR/PWR Elastomer seals, piping, 

piping components exposed to air – outdoor 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-426 

N 84 BWR/PWR Elastomer seals, piping, 

piping components exposed to condensation 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-427 

V.B.E-427 V.D1.E-427 V.D2.E-427 

N 85 BWR/PWR Nickel alloy piping, 

piping components, heat exchanger components exposed to treated water, treated borated water 

Loss of material due to pitting, crevice corrosion, MIC 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.12) 

V.A.E-428 V.D1.E-428 V.D2.E-428 

N 86 BWR/PWR Steel, stainless steel 

bolting exposed to raw water, waste water, treated water, treated borated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No V.E.E-430 

V.E.E-429 V.E.E-431 
3.2-35 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 87 BWR/PWR Jacketed thermal 

insulation in an air – indoor uncontrolled, air – outdoor environment, air with borated water leakage, air with reactor coolant leakage, air with steam or water leakage environment 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-422 

N 89 BWR/PWR Steel, stainless steel, 

nickel alloy, copper alloy, aluminum piping, piping components exposed to condensation 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No V.E.E-433 

N 90 BWR/PWR Steel components 

exposed to treated water, raw water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "OneTime Inspection" No V.A.E-434 V.B.E-434 

V.C.E-434 V.D1.E-434 V.D2.E-434 

N 91 BWR/PWR Stainless steel piping, 

piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.2.2.2.11) 

V.F.EP-20 

N 92 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components internal to components exposed to air, condensation 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.A.E-435 

V.B.E-435 V.D1.E-435 V.D2.E-435 
3.2-36 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 95 PWR Copper alloy (≤8% Al) 

piping, piping components exposed to air with borated water leakage 

None None No V.F.E-438 

N 96 BWR/PWR Stainless steel piping, 

piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.D1.E-439 

N 97 BWR Steel piping, piping 

components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No V.D2.E-440 

N 98 BWR/PWR Copper alloy (>15% Zn 

or >8% Al) piping, piping components exposed to soil ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No V.D1.E-441 

V.D2.E-441 

N 99 BWR/PWR Stainless steel tanks 

exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-442 

N 100 BWR/PWR Aluminum piping, piping 

components exposed to air – outdoor, raw water, waste water, condensation (internal) 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.A.E-443 V.B.E-443 V.D1.E-443 V.D2.E-443 
3.2-37 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 101 BWR/PWR Aluminum piping, piping 

components exposed to air – outdoor, raw water, waste water, condensation (external) 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.E-444 

N 102 BWR/PWR Aluminum tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to the following external environments: soil, concrete, air – outdoor, air – indoor uncontrolled, air – indoor controlled, condensation, raw water, waste water 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.D1.E-445 V.D2.E-445 

N 103 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – indoor uncontrolled, air – indoor controlled, moist air, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.2.2.2.5) 

V.D1.E-446 V.D2.E-446 

N 104 BWR/PWR Aluminum tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

No V.D1.E-447 

V.D2.E-447 
3.2-38 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 105 BWR/PWR Aluminum tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.13) 

V.D1.E-448 V.D2.E-448 

N 106 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – indoor uncontrolled, moist air, condensation, air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.D1.E-449 V.D2.E-449 

N 107 BWR/PWR Insulated stainless steel 

tanks exposed to condensation, air – outdoor, air – indoor uncontrolled, air – indoor controlled 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-450 

N 108 BWR/PWR Insulated stainless steel 

piping, piping components, tanks exposed to condensation, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.2.2.2.5) 

V.E.E-451 

N 109 BWR/PWR Insulated aluminum 

piping, piping components, tanks exposed to condensation, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.E.E-452 
3.2-39 

Table 3.2-1. Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 110 BWR/PWR Aluminum underground 

piping, piping components, tanks exposed to air – outdoor, raw water, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.10) 

V.B.E-453 V.C.E-453 V.D1.E-453 V.D2.E-453 

N 111 BWR/PWR Aluminum underground 

piping, piping components exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.2.2.2.13) 

V.E.E-454 

N 112 BWR/PWR Stainless steel 

underground piping, piping components exposed to raw water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No V.E.E-455 

N 113 BWR/PWR Stainless steel 

underground piping, piping components exposed to air – indoor uncontrolled, condensation, air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.2.2.2.2) 

V.E.E-456 
3.2-40 

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

Management of Engineered Safety Features 

GALL-SLR Report 

Chapter/AMP 

Program Name 

AMP XI.M2 Water Chemistry 

AMP XI.M7 Boiling Water Reactor Stress Corrosion Cracking 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless 

Steel (CASS) 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M29 Aboveground Metallic Tanks 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

GALL-SLR Report Appendix 

A 

Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix 

B 

Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Plant-Specific AMP 
3.3-1 

1 3.3 Aging Management of Auxiliary Systems 

2 Review Responsibilities 

3 Primary—Branch assigned responsibility by Project Manager (PM) as described in Standard 

4 Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

5 (SRP-SLR) Section 3.0 of this SRP-SLR. 

6 3.3.1 Areas of Review 

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

8 management program (AMP) of the auxiliary systems for subsequent license renewal (SLR). 

9 For a recent vintage plant, the information related to the auxiliary systems contained in 

10 Chapter 9, “Auxiliary Systems,” of the plant’s Final Safety Analysis Report (FSAR) consistent 

11 with the “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power 

12 Plants” (NUREG–0800). The auxiliary systems contained in this review plan section are 

13 generally consistent with those contained in NUREG–0800 except for refueling water, chilled 

14 water, heat removal, condenser circulating water, and condensate storage system. For older 

15 plants, the location of applicable information is plant-specific because an older plant’s FSAR 

16 may have predated NUREG–0800. 

17 Typical auxiliary systems that are subject to an AMR for SLR are new fuel storage, spent fuel 

18 storage, spent fuel pool cooling and cleanup [boiling water reactor/pressurized water 

19 reactor(BWR/PWR)], suppression pool cleanup (BWR), overhead heavy load and light load 

20 (related to refueling) handling, open-cycle cooling water, closed-cycle cooling water, ultimate 

21 heat sink, compressed air, chemical and volume control (PWR), standby liquid control (BWR), 

22 reactor water cleanup (BWR), shutdown cooling (older BWR), control room area ventilation, 

23 auxiliary and radwaste area ventilation, primary containment heating and ventilation, diesel 

24 generator building ventilation, fire protection, diesel fuel oil, and emergency diesel generator. 

25 This review plan section also includes structures and components in nonsafety-related systems 

26 that are not connected to safety-related systems, structures, and components (SSCs) but have 

27 a spatial relationship such that their failure could adversely impact the performance of a 

28 safety-related SSC intended function. Examples of such nonsafety-related systems may be 

29 plant drains, liquid waste processing, potable/sanitary water, water treatment, process sampling, 

30 and cooling water systems. 

31 Aging management is reviewed, following the guidance in this SRP-SLR Section 3.1, for 

32 portions of the chemical and volume control system for PWRs, and for standby liquid control, 

33 reactor water cleanup, and shutdown cooling systems extending up to the first isolation valve 

34 outside of containment for BWRs (the shutdown cooling systems for older BWRs). The 

35 following systems have portions that are classified as Group B quality standard: open-cycle 

36 cooling water (service water system), closed-cycle cooling water, compressed air, standby liquid 

37 control, shutdown cooling system (older BWR), control room area ventilation, and auxiliary and 

38 radwaste area ventilation. Aging management for these portions is reviewed following the 

39 guidance in Section 3.3. The AMP for the cooling towers is reviewed following the guidance in 

40 Section 3.5 for “Group 6” structures. 

41 The responsible review organization is to review the following SLR application AMR and AMP 

42 items assigned to it, per SRP-SLR Section 3.0: 
3.3-2 

1 AMRs 

2  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

3 License Renewal (GALL-SLR) Report 

4  AMR results for which further evaluation is recommended 

5  AMR results not consistent with or not addressed in the GALL-SLR Report 

6 AMPs 

7  Consistent with GALL-SLR Report AMPs 

8  Plant-specific AMPs 

9 FSAR Supplement 

10  The responsible review organization is to review the FSAR Supplement associated with 

11 each assigned AMP. 

12 3.3.2 Acceptance Criteria 

13 The acceptance criteria for the areas of review describe methods for determining whether the 

14 applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

15 regulations in 10 CFR 54.21. 

16 3.3.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

17 Learned for Subsequent License Renewal Report 

18 The AMR and the AMPs applicable to the auxiliary system features are described and evaluated 

19 in Chapter VII of the GALL-SLR Report. 

20 The applicant’s subsequent license renewal application (SLRA) should provide sufficient 

21 information so that the NRC reviewer is able to confirm that the specific SLRA AMR item and 

22 the associated SLRA AMP are consistent with the cited GALL-SLR Report AMR item. The 

23 reviewer should then confirm that the SLRA AMR item is consistent with the GALL-SLR Report 

24 AMR item to which it is compared. 

25 When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, 

26 the reviewer should confirm that the alternate AMP is valid to use for aging management and 

27 will be capable of managing the effects of aging as adequately as the AMP recommended by 

28 the GALL-SLR Report. 

29 3.3.2.2 Aging Management Review Results for Which Further Evaluation Is 

30 Recommended by the Generic Aging Lessons Learned for Subsequent License 

31 Renewal Report 

32 The basic acceptance criteria, defined in Subsection 3.3.2.1, need to be applied first for all of 

33 the AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR 

34 item to which the SLRA AMR item is compared identifies that “further evaluation is 

35 recommended,” then additional criteria apply as identified by the GALL-SLR Report for each of 

36 the following aging effect/aging mechanism combinations. Refer to Table 3.3-1, comparing the 
3.3-3 

1 “Further Evaluation Recommended” and the “GALL-SLR Item” column, for the AMR items that 

2 reference the following subsections. 

3 3.3.2.2.1 Cumulative Fatigue Damage 

4 Fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required 

5 to be evaluated in accordance with 10 CFR 54.21(c). This TLAA is addressed separately in 

6 Section 4.3, “Metal Fatigue Analysis,” or Section 4.7, “Other Plant-Specific Time-Limited Aging 

7 Analyses,” of this SRP-SLR. 

8 3.3.2.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

9 Cracking due to stress corrosion cracking (SCC) and cyclic loading could occur in stainless 

10 steel (SS) PWR nonregenerative heat exchanger components exposed to treated borated water 

11 greater than 60 °C [>140 °F] in the chemical and volume control system. The existing AMP on 

12 monitoring and control of primary water chemistry in PWRs manages the aging effects of 

13 cracking due to SCC. However, control of water chemistry does not preclude cracking due to 

14 SCC and cyclic loading. Therefore, the effectiveness of the water chemistry control program 

15 should be verified to ensure that cracking is not occurring. The GALL-SLR Report recommends 

16 that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic 

17 loading to ensure that these aging effects are managed adequately. An acceptable verification 

18 program is to include temperature and radioactivity monitoring of the shell side water, and eddy 

19 current testing of tubes. 

20 3.3.2.2.3 Cracking Due to Stress Corrosion Cracking 

21 Cracking due to SCC could occur for SS piping, piping components, and tanks exposed to 

22 outdoor air or any air environment when the component is insulated. The possibility of cracking 

23 also extends to indoor components located in close proximity to sources of outdoor air 

24 (e.g., components near intake vents). Cracking is known to occur in environments containing 

25 sufficient halides (e.g., chlorides) and in which moisture is possible. 

26 Applicable outdoor air environments (and associated local indoor air environments) include, but 

27 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

28 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

29 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

30 compounds, and areas subject to chloride contamination from other agricultural or industrial 

31 sources. 

32 Insulated SS components exposed to indoor air environments and outdoor air environments are 

33 susceptible to SCC if the insulation contains certain contaminants. Leakage of fluids through 

34 bolted connections (e.g., flanges, valve packing) can result in contaminants present in the 

35 insulation leaching onto the component surface. For outdoor insulated SS components, rain 

36 and changing weather conditions can result in moisture intrusion of the insulation. 

37 The applicant may demonstrate that SCC is not expected to occur by one or more of the 

38 following applicable means. 

39  For outdoor uninsulated components, describing the outdoor air environment present at 

40 the plant and demonstrating that SCC is not expected. 
3.3-4 

1  For underground components, the applicant may demonstrate that SCC due to exposure 

2 to in-leakage to the vault as a result of external precipitation or groundwater is not 

3 expected. 

4  For insulated components, determining that the insulation does not contain sufficient 

5 contaminants to cause SCC. One acceptable means to demonstrate this is provided by 

6 Regulatory Guide 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

7  For indoor components, determining that there are no liquid-filled systems with threaded 

8 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

9  For all components, demonstrating that the aggressive environment is not present by 

10 isolating the component from the environment using a barrier to prevent loss of material 

11 due to pitting or crevice corrosion. An acceptable barrier includes tightly-adhering 

12 coatings that have been demonstrated to be impermeable to aqueous solutions and 

13 atmospheric air that contain halides. If a barrier coating is credited for isolating a 

14 component from a potentially aggressive environment then the barrier coating is 

15 evaluated to verify that it is impervious to the plant-specific environment. GALL-SLR 

16 Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

17 Heat Exchangers, and Tanks,” is an acceptable method to manage the integrity of a 

18 barrier coating for internal or external coatings. 

19 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

20 to manage this aging effect based on the environmental conditions applicable to the plant and 

21 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

22 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 

23 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

24 manage cracking of SS due to SCC in piping, piping components, and tanks. 

25 3.3.2.2.4 Loss of Material Due to Pitting and Crevice Corrosion 

26 Loss of material due to pitting and crevice corrosion could occur in SS piping, piping 

27 components, and tanks exposed to outdoor air or any air environment when the component is 

28 insulated or where the component is in the vicinity of insulated components. The possibility of 

29 pitting and crevice corrosion also extends to indoor components located in close proximity to 

30 sources of outdoor air (e.g., components near intake vents). Pitting and crevice corrosion is 

31 known to occur in environments containing sufficient halides (e.g., chlorides) and in which the 

32 presence of moisture is possible. 

33 Applicable outdoor air environments (and associated local indoor air environments) include, but 

34 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

35 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

36 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

37 compounds, and areas subject to chloride contamination from other agricultural or industrial 

38 sources. 

39 Insulated SS components exposed to indoor air environments and outdoor air environments are 

40 susceptible to loss of material due to pitting or crevice corrosion if the insulation contains certain 

41 contaminants. Leakage of fluids through mechanical connections such as bolted flanges and 

42 valve packing can result in contaminants leaching onto the component surface. For outdoor 

43 insulated SS components, rain and changing weather conditions can result in moisture intrusion 

44 of the insulation. 
3.3-5 

1 The applicant may demonstrate that loss of material due to pitting and crevice corrosion is not 

2 expected to occur by one or more of the following applicable means. 

3  For outdoor uninsulated components, describing the outdoor air environment present at 

4 the plant and demonstrating that external pitting or crevice corrosion is not expected. 

5  For underground components, the applicant may demonstrate that loss of material due 

6 to pitting or crevice corrosion due to exposure to in-leakage to the vault as a result of 

7 external precipitation or groundwater is not expected. 

8  For insulated components, determining that the insulation does not contain sufficient 

9 contaminants to cause loss of material due to pitting or crevice corrosion. One 

10 acceptable means to demonstrate this is provided by Regulatory Guide 1.36, 

11 “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

12  For indoor components, determining that there are no liquid-filled systems with threaded 

13 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

14  For all components, demonstrating that the aggressive environment is not present by 

15 isolating the component from the environment using a barrier to prevent loss of material 

16 due to pitting or crevice corrosion. An acceptable barrier includes coatings that have 

17 been demonstrated to be impermeable to aqueous solutions and atmospheric air that 

18 contain halides. If a barrier coating is credited for isolating a component from a 

19 potentially aggressive environment, then the barrier coating is evaluated to verify that it 

20 is impervious to the plant-specific environment. GALL-SLR Report AMP XI.M42, 

21 “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 

22 and Tanks,” is an acceptable method to manage the integrity of a barrier coating for 

23 internal or external coatings. 

24 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

25 to manage this aging effect based on the environmental conditions applicable to the plant and 

26 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

27 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 

28 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

29 manage loss of material due to pitting and crevice corrosion in SS piping, piping components, 

30 and tanks. 

31 3.3.2.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

32 Acceptance criteria are described in Branch Technical Position (BTP) IQMB-1 

33 (Appendix A.2, of this SRP-SLR Report.) 

34 3.3.2.2.6 Ongoing Review of Operating Experience 

35 Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

36 Management Programs.” 

37 3.3.2.2.7 Loss of Material Due to Recurring Internal Corrosion 

38 Recurring internal corrosion can result in the need to augment AMPs beyond the 

39 recommendations in the GALL-SLR Report. During the search of plant-specific operating 

40 experience (OE) conducted during the SLRA development, recurring internal corrosion can be 

41 identified by the number of occurrences of aging effects and the extent of degradation at each 

42 localized corrosion site. This further evaluation item is applicable if the search of plant-specific 
3.3-6 

1 OE reveals repetitive occurrences (e.g., one per refueling outage cycle that has occurred over: 

2 (a) in any three or more—cycles for a 10-year OE search, or (b) in any two or more—cycles for 

3 a 5-year OE search) of aging effects with the same aging mechanism in which the aging effect 

4 resulted in the component either not meeting plant-specific acceptance criteria or experiencing a 

5 reduction in wall thickness greater than 50 percent (regardless of the minimum wall thickness). 

6 The GALL-SLR Report recommends that a plant-specific AMP, or a new or existing AMP, be 

7 evaluated for inclusion of augmented requirements to ensure the adequate management of any 

8 recurring aging effect(s). Potential augmented requirements include: alternative examination 

9 methods (e.g., volumetric versus external visual), augmented inspections (e.g., a greater 

10 number of locations, additional locations based on risk insights based on susceptibility to aging 

11 effect and consequences of failure, a greater frequency of inspections), and additional trending 

12 parameters and decision points where increased inspections would be implemented. 

13 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1of this SRP-SLR Report).” 

14 The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

15 recurring aging effect before affecting the ability of a component to perform its intended function, 

16 (b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

17 parameters will be trended as well as the decision points where increased inspections would be 

18 implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

19 change), (d) how inspections of components that are not easily accessed (i.e., buried, 

20 underground) will be conducted, and (e) how leaks in any involved buried or underground 

21 components will be identified. 

22 Plant-specific operating experience examples should be evaluated to determine if the chosen 

23 AMP should be augmented even if the thresholds for significance of aging effect or frequency of 

24 occurrence of aging effect have not been exceeded. For example, during a 10-year search of 

25 plant specific operating experience, two instances of 360 degree 30 percent wall loss occurred 

26 at copper alloy to steel joints. Neither the significance of the aging effect nor the frequency of 

27 occurrence of aging effect threshold has been exceeded. Nevertheless, the operating 

28 experience should be evaluated to determine if the AMP that is proposed to manage the aging 

29 effect is sufficient (e.g., method of inspection, frequency of inspection, number of inspections) to 

30 provide reasonable assurance that the current licensing basis (CLB) intended functions of the 

31 component will be met throughout the subsequent period of extended operation. Likewise, the 

32 GALL-SLR Report AMR items associated with the new further evaluation—items only cite raw 

33 water and waste water environments because OE indicates that these are the predominant 

34 environments associated with recurring internal corrosion; however, if the search of 

35 plant-specific OE reveals recurring internal corrosion in other water environments 

36 (e.g., treated water), the aging effect should be addressed in a similar manner. 

37 3.3.2.2.8 Reduction in Impact Strength 

38 Reduction in impact strength can occur in polyvinyl chloride (PVC) piping and piping 

39 components that have been exposed to sunlight 2 years or longer. If the piping had been 

40 wrapped with an opaque material or painted during installation, an AMP should include 

41 inspections of the condition of the wrap or paint. If the piping had not been wrapped or painted, 

42 a plant-specific program to address reduction in impact strength is recommended.
3.3-7 

1 3.3.2.2.9 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

2 Corrosion Cracking 

3 Cracking due to SCC and intergranular stress corrosion cracking (IGSCC) could occur in BWR 

4 SS and nickel alloy piping, piping components greater than or equal to 4 inches nominal pipe 

5 size; nozzle safe ends and associated welds; and control rod drive return line nozzle caps and 

6 the associated cap-to-nozzle welds or cap-to-safe end welds in BWR-3, BWR-4, BWR-5, and 

7 BWR-6 designs that are exposed to reactor coolant. The GALL-SLR Report recommends 

8 GALL-SLR Report AMP XI.M2, “Water Chemistry,” to mitigate SCC and IGSCC and augmented 

9 inspection activities in accordance with GALL-SLR Report AMP XI.M7, “BWR Stress Corrosion 

10 Cracking,” for condition monitoring. However, these programs may need to be augmented to 

11 manage the effects of cracking in dead-legs and other piping locations with stagnant flow where 

12 localized environmental conditions could exacerbate the mechanisms of SCC and IGSCC. The 

13 GALL-SLR Report recommends further evaluation to identify any such locations and to evaluate 

14 the adequacy of the applicant’s proposed AMPs on a case-by-case basis to ensure that the 

15 intended functions of components in these locations will be maintained during the subsequent 

16 period of extended operation. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 

17 of this SRP-SLR Report). 

18 3.3.2.2.10 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

19 SCC is a form of environmentally assisted cracking which is known to occur in high and 

20 moderate strength aluminum alloys. The three conditions necessary for SCC to occur in a 

21 component are a sustained tensile stress, aggressive environment, and material with a 

22 susceptible microstructure. The aging effect of cracking due to SCC can be mitigated by 

23 eliminating one of the three necessary conditions. For the purposes of SLR, acceptance criteria 

24 for this further evaluation is being provided for demonstrating that the specific material is not 

25 susceptible to SCC or an aggressive environment is not present. The susceptibility of the 

26 material is to be established prior to evaluating the environment. This further evaluation item is 

27 applicable unless it is demonstrated by the applicant that one of the two necessary conditions 

28 discussed below is absent. 

29 Susceptible Material: If the material of a component is not susceptible to SCC then the aging 

30 effect is not applicable. The microstructure of an aluminum alloy, of which alloy composition is 

31 only one factor, is what determines if the alloy is susceptible to SCC. Therefore, providing 

32 guidance based on alloy composition will not always successfully protect against SCC in 

33 aluminum alloys. The temper, condition, and product form of the alloy is considered when 

34 assessing if a material is susceptible to SCC. Aluminum alloys that are susceptible to 

35 SCC include: 

36  2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

37  5xxx series alloys with a magnesium content of 3.5 weight percent or greater 

38  6xxx series alloys in the F temper 

39  7xxx series alloys in the F, T5x, or T6x temper 

40  2xx.x and 7xx.x series alloys 

41  3xx.x series alloys that contain copper 

42  5xx.x series alloys with a magnesium content of greater than 8 weight percent 

43 The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

44 make the determination is technically substantiated. Tempers have been specifically developed 

45 to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 
3.3-8 

1 combination which are not susceptible to SCC when used in piping, piping component, and tank 

2 applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. 

3 GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” is an acceptable method to 

4 manage cracking of aluminum due to SCC in tanks. GALL-SLR Report AMP XI.M36, “External 

5 Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage cracking 

6 of aluminum due to SCC in piping and piping components. GALL-SLR Report AMP XI.M41, 

7 “Buried and Underground Piping and Tanks,” is an acceptable method to manage cracking of 

8 aluminum due to SCC in piping and tanks which are buried or underground. GALL-SLR Report 

9 AMP XI.M27, “Fire Water System,” is an acceptable method to manage cracking of aluminum 

10 due to SCC in fire water storage tanks. GALL-SLR Report AMP XI.M38, “Inspection of Internal 

11 Surfaces in Miscellaneous Piping and Ducting Components” is an acceptable method to 

12 manage cracking of aluminum due to SCC in components that are not included in other AMPs. 

13 Additional acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this 

14 SRP-SLR Report). 

15 Aggressive Environment: If the environment that an aluminum alloy is exposed to is not 

16 aggressive, such as dry gas, controlled indoor air, or treated water, then cracking due to SCC 

17 will not occur and the aging effect is not applicable. Aggressive environments that are known to 

18 result in cracking of susceptible aluminum alloys due to SCC are aqueous solutions and 

19 atmospheric air that contain halides (e.g., chloride). Halide concentrations should generally be 

20 considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated 

21 aqueous solutions and atmospheric air, such as outdoor air, raw water, waste water, and 

22 condensation, unless demonstrated otherwise. If an aluminum component is encapsulated in a 

23 secondary material, such as insulation or concrete, the composition of the encapsulating 

24 material is evaluated for halides. The environment that the aluminum alloy is exposed to is 

25 evaluated to verify that it is either controlled or treated and free of halides. 

26 An alternative strategy to demonstrating that an aggressive environment is not present is to 

27 isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

28 barriers include tightly adhering coatings that have been demonstrated to be impermeable to 

29 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

30 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

31 evaluated to verify that it is impervious to the plant-specific environment. GALL-SLR 

32 Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

33 Exchangers, and Tanks,” or equivalent program is an acceptable method to manage the 

34 integrity of a barrier coating. 

35 3.3.2.2.11 Loss of Material Due to General, Crevice or Pitting Corrosion and 

36 Microbiologically-Induced Corrosion and Cracking Due to Stress 

37 Corrosion Cracking 

38 Loss of material due to general (steel only), crevice, or pitting corrosion, and microbiologically39 induced corrosion and cracking due to SCC (SS only) can occur in steel and SS piping and 

40 piping components exposed to concrete. Concrete provides a high alkalinity environment that 

41 can mitigate the effects of loss of material for steel piping, thereby significantly reducing the 

42 corrosion rate. However, if water intrudes through the concrete, the pH can be reduced and 

43 ions that promote loss of material such as chlorides, which can penetrate the protective oxide 

44 layer created in the high alkalinity environment, can reach the surface of the metal. Carbonation 

45 can reduce the pH within concrete. The rate of carbonation is reduced by using concrete with a 

46 low water-to-cement ratio and low permeability. Concrete with low permeability also reduces 
3.3-9 

1 the potential for the penetration of water. Adequate air entrainment improves the ability of the 

2 concrete to resist freezing and thawing cycles and therefore reduces the potential for cracking 

3 and intrusion of water. Intrusion of water can also bring bacteria to the surface of the metal, 

4 potentially resulting in microbiologically-induced corrosion in steel or SS. Cracking due to SCC, 

5 as well as pitting and crevice corrosion can occur due to halides present in the water that 

6 penetrates to the surface of the metal. 

7 If the following conditions are met, loss of material is not considered to be an applicable aging 

8 effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

9 (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air 

10 entrainment) as cited in NUREG–1557; (b) plant-specific operating experience indicates no 

11 degradation of the concrete that could lead to penetration of water to the metal surface; and 

12 (c) the piping is not potentially exposed to groundwater. For SS components loss of material 

13 and cracking due to SCC are not considered to be applicable aging effects as long as the piping 

14 is not potentially exposed to groundwater. Where these conditions are not met, loss of material 

15 due to general (steel only), crevice, or pitting corrosion, and microbiologically-induced corrosion 

16 and cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

17 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

18 these aging effects. 

19 3.3.2.2.12 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically20 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

21 Water, or Sodium Pentaborate Solution 

22 Loss of material due to crevice corrosion can occur in steel with SS cladding, SS, and nickel 

23 alloy piping, piping components, heat exchanger components, spent fuel storage racks, tanks, 

24 and PWR heat exchanger components exposed to treated water, treated borated water, or 

25 sodium pentaborate solution if oxygen levels are greater than 100 parts per billion (ppb). In 

26 addition, loss of material due to pitting can occur if oxygen levels are greater than 100 ppb, 

27 halides or sulfates levels are greater than 150 ppb, and stagnant flow conditions exist. Loss of 

28 material due to microbiologically-induced corrosion can occur with steel with SS cladding, SS, 

29 and nickel alloy piping, piping components, heat exchanger components, spent fuel storage 

30 racks, tanks, and PWR heat exchanger components exposed to treated water, treated borated 

31 water, or sodium pentaborate solution if the pH is less than 10.5 and temperature is less than 

32 99 °C [210 °F]. 

33 Where oxygen levels are less than or equal to 100 ppb, GALL-SLR Report AMP XI.M2, “Water 

34 Chemistry,” and GALL-SLR Report AMP XI.M32, “One-Time Inspection,” are acceptable 

35 methods to manage loss of material due to pitting and crevice corrosion. Where oxygen levels 

36 are greater than 100 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR 

37 Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

38 Components,” are acceptable methods to manage loss of material due to crevice corrosion. 

39 Where stagnant flow conditions exist, and oxygen levels are greater than 100 ppb and halides 

40 or sulfates levels are greater than 150 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” 

41 and GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

42 and Ducting Components,” are acceptable methods to manage loss of material due to pitting 

43 and crevice corrosion. 

44 Where the pH is greater than or equal to 10.5 and the temperature is greater than or equal to 

45 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR Report 

46 AMP XI.M32, “One-Time Inspection,” are acceptable methods to manage loss of material due to 
3.3-10 

1 microbiologically-induced corrosion. Where the pH is less than 10.5 and temperature is less 

2 than 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR Report 

3 AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

4 Components,” are acceptable methods to manage loss of material due to MIC. 

5 For tanks and spent fuel storage racks, due to the restricted accessibility for inspections, 

6 GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

7 Ducting Components,” is an acceptable method to manage loss of material due to pitting and 

8 crevice corrosion even though the surface exposed to the environment may not be an 

9 interior surface. 

10 3.3.2.2.13 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

11 Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

12 components, and tanks exposed to an air environment for a sufficient duration of time. Air 

13 environments known to result in pitting and/or crevice corrosion of aluminum alloys are those 

14 that contain halides (e.g., chloride) and periodic moisture. The moisture level and halide 

15 concentration in atmospheric and uncontrolled air are greatly dependent on geographical 

16 location and site-specific conditions. Moisture level and halide concentration should generally 

17 be considered high enough to facilitate pitting and/or crevice corrosion of aluminum alloys in 

18 atmospheric and uncontrolled air, unless demonstrated otherwise. The periodic introduction of 

19 moisture or halides into an air environment from secondary sources should also be considered. 

20 Leakage of fluids from mechanical connections, such as bolted flanges and valve packing, 

21 through insulation onto a component in indoor controlled air is an example of a secondary 

22 source that should be considered. The operating experience (OE) and condition of aluminum 

23 alloy components are evaluated to determine if the plant-specific air environment is aggressive 

24 enough to result in pitting and crevice corrosion after prolonged exposure. The aging effect of 

25 loss of material due to pitting and crevice corrosion in aluminum alloys is not applicable and 

26 does not require management if: (a) the plant-specific OE does not reveal a history of pitting or 

27 crevice corrosion and (b) a one-time inspection demonstrates that the aging effect is not 

28 occurring or that loss of material due to pitting or crevice corrosion is occurring so slowly that it 

29 will not affect the intended function of the components. 

30 The internal surfaces of aluminum components do not need to be inspected if: (a) the review of 

31 OE does not reveal a history of pitting or crevice corrosion; and (b) inspection results for 

32 external surfaces demonstrate that the aging effect is not applicable. Inspection results 

33 associated with the periodic introduction of moisture or halides from secondary sources may be 

34 treated as a separate population of components. In the environment of air-indoor controlled, 

35 pitting and crevice corrosion is only expected to occur as the result of secondary source of 

36 moisture or halides. Alloy susceptibility may be considered when reviewing OE and interpreting 

37 inspection results. Inspections focus on the most susceptible alloys and locations. 

38 The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

39 components, and tanks exposed to an air environment to determine whether an AMP is needed 

40 to manage the aging effect of loss of material due to pitting and crevice corrosion. GALL-SLR 

41 Report AMP XI.M32, “One-Time Inspection,” is an acceptable method to demonstrate that the 

42 aging effect of loss of material due to pitting and crevice corrosion is not occurring at a rate that 

43 affects the intended function of the components. If loss of material due to pitting or crevice 

44 corrosion has occurred and is sufficient to potentially affect the intended function of an 

45 aluminum SSC, the following AMPs are acceptable methods to manage loss of material due to 

46 pitting or crevice corrosion: (i) GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” 
3.3-11 

1 for tanks; (ii) GALL-SLR Report AMP XI.M36, "External Surfaces Monitoring of Mechanical 

2 Components,” for external surfaces of piping and piping components; (iii) GALL-SLR Report 

3 AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground piping, piping 

4 components and tanks; and (iv) GALL-SLR Report Chapter XI.M38, "Inspection of Internal 

5 Surfaces in Miscellaneous Piping and Ducting Components” for internal surfaces of components 

6 that are not included in other aging management programs. 

7 3.3.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

8 Generic Aging Lessons Learned for Subsequent License Renewal Report 

9 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report.) 

10 3.3.2.4 Aging Management Programs 

11 For those AMPs that will be used for aging management and are based on the program 

12 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

13 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

14 GALL-SLR Report, Chapters X and XI. 

15 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

16 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

17 10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

18 AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

19 SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

20 Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, 

21 the difference should be reviewed and properly dispositioned. The reviewer should document 

22 the disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

23 The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP 

24 to be declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is 

25 compared. The reviewer is to confirm both that the enhancement, when implemented, would 

26 allow the existing license renewal applications (LRA) AMP to be consistent with the GALL-SLR 

27 Report AMP and also that the applicant has a commitment in the FSAR Supplement to 

28 implement the enhancement prior to the subsequent period of extended operation. The 

29 reviewer should document the disposition of all enhancements. 

30 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

31 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

32 (Appendix A.1.2.3 of this SRP-SLR). 

33 3.3.2.5 Final Safety Analysis Report Supplement 

34 The summary description of the programs and activities for managing the effects of aging for the 

35 subsequent period of extended operation in the FSAR Supplement should be sufficiently 

36 comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

37 should contain information associated with the bases for determining that aging effects will be 

38 managed during the subsequent period of extended operation. The description should also 

39 contain any future aging management activities, including enhancements and commitments, to 

40 be completed before the period of extended operation. Table 3.3-2 lists the programs that are 

41 applicable for this SRP-SLR subsection. 
3.3-12 

1 3.3.3 Review Procedures 

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

3 3.3.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

4 Learned for Subsequent License Renewal Report 

5 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

6 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

7 approved in the GALL-SLR Report. The reviewer should not conduct a re-review of the 

8 substance of the matters described in the GALL-SLR Report. If the applicant has provided the 

9 information necessary to adopt the finding of program acceptability as described and evaluated 

10 in the GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to the 

11 GALL-SLR Report in its SLRA. In making this determination, the reviewer confirms that the 

12 applicant has provided a brief description of the system, components, materials, and 

13 environment. The reviewer also confirms that the applicable aging effects have been addressed 

14 based in the staff’s review of industry and plant-specific operating experience. 

15 Furthermore, the reviewer should confirm that the applicant has addressed operating 

16 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

17 requires the reviewer to confirm that the applicant has identified those aging effects for the 

18 auxiliary system components that are contained in the GALL-SLR Report as applicable to 

19 its plant. 

20 3.3.3.2 Aging Management Review Results Report for Which Further Evaluation Is 

21 Recommended by the Generic Aging Lessons Learned for Subsequent License 

22 Renewal Report 

23 The basic review procedures defined in Subsection 3.3.3.1 need to be applied first for all of the 

24 AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to 

25 which the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

26 additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

27 effect/aging mechanism combinations. Refer to Table 3.3-1 for the items that reference the 

28 following subsections. 

29 3.3.3.2.1 Cumulative Fatigue Damage 

30 Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

31 accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in 

32 Section 4.3 of this SRP-SLR. 

33 3.3.3.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

34 The GALL-SLR Report also recommends further evaluation of programs to manage cracking 

35 due to SCC and cyclic loading in the SS nonregenerative heat exchangers in the chemical and 

36 volume control system (PWR) exposed to treated borated water >60 °C [>140 °F]. The water 

37 chemistry program relies on monitoring and control of water chemistry to manage the aging 

38 effects of cracking due to SCC and cyclic loading. The GALL-SLR Report recommends the 

39 effectiveness of the chemistry control program be verified to ensure that cracking is not 

40 occurring. The absence of cracking due to SCC and cyclic loading is to be verified. An 

41 acceptable verification program is to include temperature and radioactivity monitoring of the 
3.3-13 

1 shell side water, and eddy current testing of tubes. The reviewer reviews the applicant’s 

2 proposed program on a case-by-case basis to ensure that an adequate program will be in place 

3 for the management of these aging effects. 

4 3.3.3.2.3 Cracking Due to Stress Corrosion Cracking 

5 The GALL-SLR Report recommends further evaluation to manage cracking due to SCC of SS 

6 and aluminum piping, piping components, and tanks exposed to outdoor air environments 

7 containing sufficient halides (e.g., chlorides) and in which condensation is possible. The 

8 possibility of cracking also extends to components exposed to air which has recently been 

9 introduced into buildings (i.e., components near intake vents.) 

10 If the applicant claims that neither the environment nor composition of insulation will result in 

11 stress corrosion cracking, the reviewer should evaluate the applicant’s data to verify that 

12 sufficient halides will not be present on the surface of the SS piping, piping components, or 

13 tanks. If the applicant elects to manage stress corrosion cracking, the reviewer should 

14 determine whether an adequate program is credited to manage the aging effect based on the 

15 applicable environmental conditions. 

16 3.3.3.2.4 Loss of Material Due to Pitting and Crevice Corrosion 

17 The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

18 and crevice corrosion of SS piping, piping components, and tanks exposed to outdoor air or any 

19 air environment when the component is insulated where the presence of sufficient halides 

20 (e.g., chlorides) and moisture is possible. The possibility of pitting and crevice corrosion 

21 also extends to indoor components located in close proximity to sources of outdoor air 

22 (e.g., components near intake vents). 

23 If the applicant claims that neither the environment nor composition of the insulation will result in 

24 loss of material due to pitting and crevice corrosion, the reviewer should evaluate the applicant’s 

25 data to verify that sufficient halides will not be present on the surface of the SS piping, piping 

26 components, or tanks. If the applicant elects to manage loss of material due to pitting or crevice 

27 corrosion, the reviewer should determine whether an adequate program is credited to manage 

28 the aging effect based on the applicable environmental conditions. 

29 3.3.3.2.5 Quality Assurance for Aging Management of Nonsafety-Related Components 

30 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

31 confirmation process, and administrative controls. Safety-related components are covered by 

32 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

33 Appendix B does not apply to nonsafety-related components that are subject to an AMR for 

34 SLR. Nevertheless, the applicant has the option to expand the scope of its 10 CFR Part 50, 

35 Appendix B program to include these components and address the associated program 

36 elements. If the applicant chooses this option, the reviewer verifies that the applicant has 

37 documented such a commitment in the FSAR Supplement. If the applicant chooses alternative 

38 means, the branch responsible for quality assurance (QA) should be requested to review the 

39 applicant’s proposal on a case-by-case basis. 

40 3.3.3.2.6 Ongoing Review of Operating Experience 

41 The applicant’s AMPs should contain the element of OE. The reviewer verifies that the 

42 applicant has appropriate programs or processes for the ongoing review of both plant-specific 
3.3-14 

1 and industry OE concerning age-related degradation and aging management. Such reviews are 

2 used to ensure that the AMPs are effective to manage the aging effects for which they are 

3 created. The AMPs are either enhanced or new AMPs are developed, as appropriate, when it is 

4 determined through the evaluation of OE that the effects of aging may not be adequately 

5 managed. Additional information is in Appendix A.4, “Operating Experience for Aging 

6 Management Programs.” 

7 3.3.3.2.7 Loss of Material Due to Recurring Internal Corrosion 

8 The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

9 aging effects. The reviewer conducts an independent review of plant-specific OE to determine 

10 whether the plant is currently experiencing recurring internal corrosion. The scope of this further 

11 evaluation AMR item includes recurring aging effects in which the plant-specific OE review 

12 reveals repetitive occurrences (e.g., one per refueling outage that has occurred over: (a) in any 

13 three or more cycles for a 10-year OE search, or (b) in any two or more cycles for a 5-year OE 

14 search) of aging effects with the same aging mechanism as a result of which the component 

15 either did not meet plant-specific acceptance criteria or experienced a reduction in wall 

16 thickness greater than 50 percent (regardless of the minimum wall thickness). 

17 The reviewer should evaluate plant-specific operating experience examples to determine if the 

18 chosen AMP should be augmented. For example, during a 10-year search of plant specific OE, 

19 two instances of 360 degree 30 percent wall loss occurred at copper alloy to steel joints. 

20 Neither the significance of the aging effect nor the frequency of occurrence of aging effect 

21 threshold has been exceeded. Nevertheless, the OE should be evaluated to determine if the 

22 AMP that is proposed to manage the aging effect is sufficient (e.g., method of inspection, 

23 frequency of inspection, number of inspections) to provide reasonable assurance that the CLB 

24 intended functions of the component will be met throughout the subsequent period of extended 

25 operation. Likewise, the GALL-SLR Report AMR items associated with the new further 

26 evaluation (FE) items only cite raw water and waste water environments because OE indicates 

27 that these are the predominant environments associated with recurring internal corrosion; 

28 however, if the search of plant-specific OE reveals recurring internal corrosion in other water 

29 environments (e.g., treated water), the aging effect should be addressed in a similar manner. 

30 The reviewer determines whether a proposed program is adequate to manage recurring internal 

31 corrosion by evaluating the proposed AMP against the criteria in SRP-SLR Section 3.3.2.2.7. 

32 3.3.3.2.8 Reduction in Impact Strength 

33 The reviewer should confirm that PVC piping and piping components, exposed to sunlight had 

34 been wrapped with an opaque material or painted during installation or determine whether an 

35 adequate program is used to manage reduction in impact strength for PVC piping exposed to 

36 sunlight. If the PVC piping and piping components exposed to sunlight had been wrapped with 

37 an opaque material or painted, the reviewer should confirm the adequacy of the program used 

38 to conduct inspections of the wrap or paint. 

39 3.3.3.2.9 Cracking Due to Stress Corrosion Cracking and Intergranular Stress 

40 Corrosion Cracking 

41 The GALL-SLR Report recommends review of plant-specific AMPs for managing cracking due 

42 to SCC and IGSCC in BWR SS and nickel alloy piping and piping components greater than or 

43 equal to 4 inches nominal pipe size; nozzle safe ends and associated welds; and control rod 
3.3-15 

1 drive return line nozzle caps and the associated cap-to-nozzle welds or cap-to-safe end welds in 

2 BWR-3, BWR-4, BWR-5, and BWR-6 designs that are exposed to reactor coolant. Components 

3 in dead-legs and other piping locations with stagnant flow may be subject to localized 

4 environmental conditions that could exacerbate the mechanisms of SCC and IGSCC. The 

5 reviewer ensures that the applicant has identified any such locations and provided justification 

6 for the AMPs credited for managing this aging effect. The reviewer reviews the applicant’s 

7 justification and proposed AMPs on a case-by-case basis to ensure that the effects of aging will 

8 be adequately managed. 

9 3.3.3.2.10 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

10 The GALL-SLR Report recommends the further evaluation of aluminum components 

11 (i.e., piping, piping components, and tanks) exposed to atmospheric air or aqueous solutions 

12 that contain halides to manage cracking due to SCC. The reviewer first determines if the aging 

13 effect of cracking due to SCC is applicable and requires aging management. The aging effect 

14 of cracking is to be considered applicable unless it is demonstrated that one of the two 

15 acceptance criteria are met by demonstrating that an aggressive environment is not present or 

16 the specific material is not susceptible, as discussed in Section 3.3.2.2.10. Additionally, 

17 guidance is also provided on the review of the third condition necessary for SCC to occur, a 

18 sustained tensile stress. Each of three conditions is evaluated based on the review 

19 procedures below. 

20 Susceptible Material: If the material of the component being evaluated is not susceptible to 

21 SCC then the aging effect of cracking due to SCC is not applicable and does not require aging 

22 management. When determining if an aluminum alloy is susceptible to SCC the reviewer is to 

23 verify the material’s (a) alloy composition, (b) condition or temper, and (c) product form. 

24 Additionally, if the material was produced using a process specifically developed to provide a 

25 SCC resistant microstructure then the reviewer will consider the effects of this processing in the 

26 review. Once the material information has been established the reviewer is to evaluate the 

27 technical justification used to substantiate that the material is not susceptible to SCC when 

28 exposed to an aggressive environment and sustained tensile stress. The reviewer will evaluate 

29 all documentation and references used by the applicant as part of a technical justification. 

30 Aggressive Environment: If the environment that an aluminum alloy is exposed to is not 

31 aggressive, such as dry gas, controlled indoor air, or treated water, then the aging effect of 

32 cracking due to SCC is not applicable and does not require aging management. The 

33 environments cited in the AMR line items in the GALL-SLR Report that reference this further 

34 evaluation are considered to be aggressive and potentially containing halide concentrations that 

35 facilitate SCC of aluminum alloys. The reviewer is to verify that components are not also 

36 periodically exposed to nontypical environments that would be categorized as aggressive, such 

37 as outdoor air which has recently been introduced into a building and the leakage/seepage of 

38 untreated aqueous solutions into a building or underground vault. Using information provided 

39 by the applicant, the reviewer will also evaluate the chemical composition of applicable 

40 encapsulating materials (e.g., concrete, insulation) for halides. 

41 If a barrier coating is employed to effectively isolate the aluminum alloy from an aggressive 

42 environment then the aging effect of cracking due to SCC is not applicable and does not require 

43 aging management. The reviewer is to verify that the barrier coating is impermeable to the 

44 plant-specific aqueous solutions and atmospheric air that the coating is intended to protect the 

45 alloy from being exposed to. If operating experience is cited as a technical justification for the 
3.3-16 

1 effectiveness of a barrier coating the reviewer is to verify that the applicant has a program to 

2 manage loss of coating integrity equivalent to GALL-SLR Report AMP XI.M42. 

3 Sustained Tensile Stress: If the sustained tensile stress being experienced by a component is 

4 below the SCC threshold value then cracking will not occur and the aging effect is not 

5 applicable. Many aluminum alloys do not have a true SCC threshold stress, although a practical 

6 SCC threshold value can be determined based on the material, service environment, and 

7 duration of intended function. The basis for the SCC threshold value is to be evaluated to 

8 determine its applicability. The magnitude of the maximum tensile service stress (applied and 

9 residual) experienced by the component is to be evaluated to verify that the stress levels are 

10 bounded by the SCC threshold value. 

11 The information necessary to eliminate the aging effect of SCC based on the sustained service 

12 stress is often not readily available. The SCC threshold stress level is dependent on both the 

13 alloy (e.g., chemical composition, processing history, and microstructure) and service 

14 environment. Furthermore, the magnitude and state of the residual stress sustained by a 

15 component is typically not fully characterized. The reviewer must determine the adequacy of 

16 both the SCC threshold value being used by the applicant and the magnitude of the tensile 

17 stress being experienced by the component. The evaluation of the SCC threshold value 

18 includes the verification that the (a) test method used to establish the threshold value is 

19 standardized and recognized by the industry, (b) data is statistically significant or conservative, 

20 and (c) data is for a relevant alloy, temper, product form, and environment. The evaluation of 

21 the tensile stress being experienced by the component includes the verification that the stress 

22 analysis accounts for (e) all applied and residual stresses and (f) stress raiser that can initiate 

23 SCC cracks, such as corrosion pits and fabrication defects. 

24 Documentation that may assist the reviewer in determining if the aging effect of cracking due to 

25 SCC is applicable and requires aging management include (a) component drawings, 

26 (b) applicable Codes or specifications used in the design, fabrication, and installation of the 

27 component, (c) material-specific material certification data and lot release data, and 

28 (d) maintenance records and plant-specific operating experience. 

29 If it is determined that the aging effect of cracking due to SCC is applicable the reviewer is to 

30 evaluate the applicants proposed AMP to ensure that the effects of aging on components are 

31 adequately managed so that their intended functions will be maintained consistent with the CLB 

32 for the subsequent period of extended operation. GALL-SLR Report AMP XI.M29, 

33 “Aboveground Metallic Tanks,” is an acceptable method to manage cracking of aluminum due to 

34 SCC in tanks. GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

35 Components,” is an acceptable method to manage cracking of aluminum due to SCC in piping 

36 and piping components. GALL-SLR Report AMP XI.M41, “Buried and Underground Piping and 

37 Tanks,” is an acceptable method to manage cracking of aluminum due to SCC in piping and 

38 tanks which are buried or underground. GALL-SLR Report AMP XI.M27, “Fire Water System,” 

39 is an acceptable method to manage cracking of aluminum due to SCC in fire water storage 

40 tanks. GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

41 and Ducting Components” is an acceptable method to manage cracking of aluminum due to 

42 SCC in components that are not included in other AMPs. 
3.3-17 

1 3.3.3.2.11 Loss of Material Due to General, Crevice or Pitting Corrosion and 

2 Microbiologically-Induced Corrosion and Cracking Due to Stress 

3 Corrosion Cracking 

4 The GALL-SLR Report recommends that for steel piping and piping components exposed to 

5 concrete, if the following conditions are met, loss of material is not considered to be an 

6 applicable aging effect for steel: (a) attributes of the concrete are consistent with ACI 318 or 

7 ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in 

8 NUREG–1557; (b) plant-specific operating experience indicates no degradation of the concrete 

9 that could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

10 exposed to groundwater. For SS piping and piping components, loss of material and cracking 

11 due to SCC are not considered to be applicable aging effects as long as the piping is not 

12 potentially exposed to groundwater. Where these conditions are not met, loss of material due to 

13 general (steel only), crevice, or pitting corrosion and microbiologically-induced corrosion and 

14 cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

15 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

16 these aging effects. 

17 The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-to18 cement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

19 reviewer should evaluate plant-specific operating experience to determine whether concrete 

20 degradation sufficient to allow water intrusion has occurred. 

21 3.3.3.2.12 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically22 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

23 Water, or Sodium Pentaborate Solution 

24 The GALL-SLR Report recommends that loss of material due to crevice corrosion can occur in 

25 steel with SS cladding, SS, and nickel alloy piping, piping components, heat exchanger 

26 components, spent fuel storage racks, tanks, and PWR heat exchanger components exposed to 

27 treated water, treated borated water, or sodium pentaborate solution if oxygen levels are greater 

28 than 100 ppb. In addition, loss of material due to pitting can occur if oxygen levels are greater 

29 than 100 ppb, halides or sulfates levels are greater than 150 ppb, and stagnant flow conditions 

30 exist. Loss of material due to microbiologically-induced corrosion can occur with steel with SS 

31 cladding, SS, and nickel alloy piping, piping components, heat exchanger components, spent 

32 fuel storage racks, tanks, and PWR heat exchanger components exposed to treated water, 

33 treated borated water, or sodium pentaborate solution if the pH is less than 10.5 and 

34 temperature is less than 99 °C [210 °F]. 

35 The reviewer verifies the applicant’s chemistry control parameters to determine whether 

36 GALL-SLR Report AMP XI.M2, “Water Chemistry,” and a one-time inspection program is 

37 implemented (e.g., GALL-SLR Report AMP XI.M32, “One-Time Inspection”) or GALL-SLR 

38 Report AMP XI.M2, “Water Chemistry,” and a periodic inspection program is implemented 

39 (e.g., GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

40 and Ducting Components”) to manage loss of material. 

41 3.3.3.2.13 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

42 The GALL-SLR Report recommends a further evaluation to determine whether an AMP is 

43 needed to manage the aging effect of loss of material due to pitting and crevice corrosion of 

44 aluminum piping, piping components, and tanks exposed to an air environment. If the applicant 

45 claims that a search of 10 years of plant-specific did not reveal any instances of loss of material 
3.3-18 

1 due to pitting and crevice corrosion exposed to air environments, the staff conducts an 

2 independent review of plant-specific operating experience during the AMP audit. 

3 An alternative strategy to demonstrating that pitting and crevice corrosion is not applicable is to 

4 isolate the aluminum alloy from the air environment using a barrier. Acceptable barriers include 

5 anodization and tightly adhering coatings that have been demonstrated to be impermeable to 

6 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

7 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

8 evaluated to verify that it is impermeable to the plant-specific environment. GALL-SLR Report 

9 AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

10 Exchangers, and Tanks,” is an acceptable method to manage the integrity of internal and 

11 external barrier coatings. 

12 The reviewer is to verify that the SLRA cites the use of GALL-SLR AMP XI.M32, "One-Time 

13 Inspection,” for all aluminum piping, piping components, and tanks exposed to air environments. 

14 Alternatively, if the applicant states that it will utilize a strategy of isolating the aluminum 

15 components from the environment, verify that the aluminum components are coated and 

16 GALL-SLR AMP XI.M42 has been cited to manage loss of coating integrity. 

17 3.3.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

18 Generic Aging Lessons Learned for Subsequent License Renewal Report 

19 The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging 

20 effects, listed the appropriate combination of materials and environments, and has credited 

21 AMPs that will adequately manage the aging effects. The AMP credited by the applicant 

22 could be an AMP that is described and evaluated in the GALL-SLR Report or a plant-specific 

23 program. Review procedures are described in BTP RLSB-1 (Appendix A.1 of this 

24 SRP-SLR Report). 

25 3.3.3.4 Aging Management Programs 

26 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

27 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

28 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

29 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

30 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

31 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

32 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

33 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which 

34 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

35 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

36 enhancements, exceptions or differences. The AMPs evaluated in the GALL-SLR Report 

37 pertinent to the auxiliary systems components are summarized in Table 3.3-1 of this SRP-SLR. 

38 The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR Report, 

39 Chapter VII, presenting detailed information summarized by this row. 

40 3.3.4 Evaluation Findings 

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

42 provisions of this section, then an evaluation finding similar to the following text should be 

43 included in the NRC staff’s safety evaluation report: 
3.3-19 

1 On the basis of its review, as discussed above, the NRC staff concludes that the 

2 applicant has demonstrated that the aging effects associated with the auxiliary 

3 systems components will be adequately managed so that the intended functions 

4 will be maintained consistent with the CLB for the subsequent period of extended 

5 operation, as required by 10 CFR 54.21(a)(3). 

6 The NRC staff also reviewed the applicable FSAR Supplement program summaries and 

7 concludes that they adequately describe the AMPs credited for managing aging of the 

8 auxiliary systems, as required by 10 CFR 54.21(d). 

9 3.3.5 Implementation 

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

11 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

13 3.3.6 References 

14 1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

15 for Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

16 March 2007. 

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

18 0 CFR Part 54–The License Renewal Rule.” Revision 6. Washington, DC: 

19 Nuclear Energy Institute. 

20 3. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

21 Components.” ASME Boiler and Pressure Vessel Code, 2004 Edition. New York City, 

22 New York: The American Society of Mechanical Engineers. 

23 4. ASTM International. “Standard Test Method for Water in Petroleum Products and 

24 Bituminous Materials by Distillation.” D95-83. West Conshohocken, Pennsylvania, 

25 American Society for Testing and Materials. 1990. 
3.3-20 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 1 BWR/PWR Steel cranes: structural girders 

exposed to air – indoor uncontrolled (external), air – outdoor 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.7 "Other PlantSpecific TLAAs" 

Yes (SRP-SLR Section 3.3.2.2.1) 

VII.B.A-06 

M 2 BWR/PWR Stainless steel, steel heat 

exchanger components and tubes, piping, piping components exposed to treated borated water, air - indoor, uncontrolled, treated water 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.3.2.2.1) 

VII.E1.A-100 VII.E1.A-34 VII.E1.A-57 VII.E3.A-34 VII.E3.A-62 VII.E4.A-62 

M 3 PWR Stainless steel heat exchanger 

components, non-regenerative exposed to treated borated water >60°C (>140°F) 

Cracking due to stress corrosion cracking; cyclic loading 

AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.3.2.2.2) 

VII.E1.A-69 

M 4 BWR/PWR Stainless steel piping, piping 

components exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.C1.AP-209VII.C2.AP-209VII.C3.AP-209VII.D.AP-209 VII.E1.AP-209VII.E4.AP-209VII.F1.AP-209VII.F2.AP-209VII.F4.AP-209VII.G.AP-209 VII.H1.AP-209VII.H2.AP-209 

D 5 M 6 BWR/PWR Stainless steel piping, piping 

components exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.C1.AP-221VII.C2.AP-221VII.C3.AP-221VII.D.AP-221 
3.3-21 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Mechanical Components" 

VII.E1.AP-221VII.E4.AP-221VII.F1.AP-221VII.F2.AP-221VII.F4.AP-221VII.G.AP-221 VII.H1.AP-221VII.H2.AP-221 

 7 PWR Stainless steel high-pressure 

pump, casing exposed to treated borated water 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No VII.E1.AP-115 

 8 PWR Stainless steel heat exchanger 

components and tubes exposed to treated borated water >60°C (>140°F) 

Cracking due to cyclic loading 

AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 

No VII.E1.AP-119 

M 9 PWR Steel, aluminum, copper alloy 

(>15% Zn) external surfaces, piping, piping components, bolting exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No VII.A3.A-79 

VII.A3.AP-1 VII.E1.A-79 VII.E1.AP-1 VII.I.A-102 VII.I.A-79 VII.I.AP-66 

 10 BWR/PWR Steel, high-strength closure 

bolting exposed to air with steam or water leakage 

Cracking due to stress corrosion cracking; cyclic loading 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-04 
3.3-22 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

 11 BWR/PWR Steel, high-strength highpressure pump, closure bolting 

exposed to air with steam or water leakage 

Cracking due to stress corrosion cracking; cyclic loading 

AMP XI.M18, "Bolting Integrity" 

No VII.E1.AP-122 

 12 BWR/PWR Steel; stainless steel closure 

bolting, bolting exposed to condensation, air – indoor uncontrolled (external), air – outdoor (external) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No VII.D.AP-121 

VII.I.AP-125 VII.I.AP-126 

 13 BWR/PWR Steel closure bolting exposed 

to air with steam or water leakage 

Loss of material due to general corrosion 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-03 

M 14 BWR/PWR Steel, stainless steel bolting 

exposed to soil 

Loss of preload due to thermal effects, gasket creep, or selfloosening 

AMP XI.M18, "Bolting Integrity" 

No VII.I.AP-242 

VII.I.AP-244 

M 15 BWR/PWR Steel; stainless steel, copper 

alloy, nickel alloy, stainless steel closure bolting, bolting exposed to air – indoor uncontrolled (external), any environment, air – outdoor (external), raw water, waste water, treated borated water, fuel oil, treated water 

Loss of preload due to thermal effects, gasket creep, or selfloosening 

AMP XI.M18, "Bolting Integrity" 

No VII.I.AP-124 

VII.I.AP-261 VII.I.AP-262 VII.I.AP-263 VII.I.AP-264 VII.I.AP-265 VII.I.AP-266 VII.I.AP-267 

M 16 BWR Stainless steel piping, piping 

components, outboard the second containment isolation valves with a diameter ≥4 inches nominal pipe size exposed to treated water > 93°C (> 200°F) 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M25, "BWR Reactor Water Cleanup System" 

No VII.E3.AP-283 
3.3-23 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

 17 BWR/PWR Stainless steel heat exchanger 

tubes exposed to treated water, treated borated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-139

VII.A3.A-101 VII.E1.A-101 

M 18 BWR/PWR Stainless steel high-pressure 

pump, casing, piping, piping components, exposed to treated borated water >60°C (>140°F), sodium pentaborate solution >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E1.AP-114

VII.E2.AP-181 

 19 BWR/PWR Stainless steel regenerative 

heat exchanger components exposed to treated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.AP-120 

M 20 BWR/PWR Stainless steel, steel with 

stainless steel cladding heat exchanger components exposed to treated borated water >60°C (>140°F), treated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E1.AP-118

VII.E3.AP-112 

M 21 BWR Steel piping, piping 

components, exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.AP-106

VII.E4.AP-106 

M 22 BWR Copper alloy piping, piping 

components, exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time 

No VII.A4.AP-140

VII.E3.AP-140VII.E4.AP-140 
3.3-24 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Inspection" 

D 23 D 24 M 25 BWR Aluminum piping exposed to 

treated water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No 

VII.A4.AP-130VII.E3.AP-130VII.E4.AP-130 

 26 BWR/PWR Steel with stainless steel 

cladding piping, piping components exposed to treated water 

Loss of material due to pitting, crevice corrosion (only after cladding degradation) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A4.AP-108 

 27 BWR Stainless steel heat exchanger 

tubes exposed to treated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.E3.AP-139 

M 28 PWR Stainless steel piping, piping 

components, tanks exposed to treated borated water 

Cracking due to stress corrosion cracking, MIC 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.12) 

VII.E1.AP-82 
3.3-25 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 29 PWR Steel (with stainless steel 

cladding); stainless steel piping, piping components exposed to treated borated water 

Loss of material due to pitting, crevice corrosion, MIC 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.12) 

VII.E1.A-88 

M 30 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water 

Changes in material properties due to aggressive chemical attack 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-250 

M 30.2 BWR/PWR Fiberglass, HDPE piping, 

piping components exposed to raw water (internal) 

Cracking, blistering, change in color due to water absorption 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-238

VII.C1.AP-239 

M 31 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water 

Cracking due to settling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-248 

M 32 BWR/PWR Reinforced concrete, asbestos 

cement piping, piping components exposed to raw water 

Cracking due to aggressive chemical attack and leaching; changes in material properties due to aggressive chemical attack 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-155 

M 32.5 BWR/PWR Elastomer seals, piping, piping 

components exposed to raw water 

Hardening and loss of strength due to elastomer degradation; loss of material due to wear 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.AP-75 

VII.C1.AP-76 VII.G.AP-75 VII.G.AP-76 
3.3-26 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 33 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water 

Loss of material due to abrasion, cavitation, aggressive chemical attack, leaching 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-249 

M 34 BWR/PWR Nickel alloy, copper alloy 

piping, piping components exposed to raw water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-206

VII.C3.AP-195VII.C3.AP-206 

M 35 BWR/PWR Copper alloy piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.H2.AP-193 

M 36 BWR/PWR Copper alloy piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-196 

M 37 BWR/PWR Steel piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-194

VII.C3.AP-194VII.H2.AP-194 
3.3-27 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 38 BWR/PWR Copper alloy, steel heat 

exchanger components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.AP-179

VII.C1.AP-183 

M 39 BWR/PWR Stainless steel piping, piping 

components, exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C3.A-53 

M 40 BWR/PWR Stainless steel piping, piping 

components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.A-54 

M 41 BWR/PWR Stainless steel piping, piping 

components, exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.H2.AP-55 

 42 BWR/PWR Copper alloy, titanium, 

stainless steel heat exchanger tubes exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "Open-Cycle Cooling Water System" 

No VII.C1.A-72 

VII.C1.AP-153VII.C1.AP-187VII.C3.AP-187VII.G.AP-187 VII.H2.AP-187 

M 43 BWR/PWR Stainless steel piping, piping 

components, exposed to closed- cycle cooling water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-186

VII.E3.AP-186VII.E4.AP-186 
3.3-28 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

 44 BWR/PWR Stainless steel; steel with 

stainless steel cladding heat exchanger components exposed to closed-cycle cooling water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.E3.AP-192 

M 45 BWR/PWR Steel piping, piping 

components, tanks exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-202

VII.F1.AP-202VII.F2.AP-202VII.F3.AP-202VII.F4.AP-202VII.H2.AP-202 

M 46 BWR/PWR Steel, copper alloy heat 

exchanger components, piping, piping components exposed to closed- cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.A3.AP-189

VII.A3.AP-199VII.A4.AP-189VII.A4.AP-199VII.C2.AP-189VII.C2.AP-199VII.E1.AP-189VII.E1.AP-199VII.E1.AP-203VII.E3.AP-189VII.E3.AP-199VII.E4.AP-189VII.E4.AP-199VII.F1.AP-189VII.F1.AP-199VII.F1.AP-203VII.F2.AP-189VII.F2.AP-199VII.F3.AP-189VII.F3.AP-199VII.F3.AP-203VII.F4.AP-189VII.F4.AP-199VII.H1.AP-199
3.3-29 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.H2.AP-199 

M 47 BWR Stainless steel; steel with 

stainless steel cladding heat exchanger components exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.E3.AP-191

VII.E4.AP-191 

M 48 BWR/PWR Aluminum piping, piping 

components exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-254

VII.H2.AP-255 

M 49 BWR/PWR Stainless steel piping, piping 

components, exposed to closed-cycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-52 

 50 BWR/PWR Stainless steel, copper alloy, 

steel heat exchanger tubes exposed to closed-cycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.AP-188

VII.C2.AP-205VII.E3.AP-188VII.E4.AP-188VII.F1.AP-204VII.F1.AP-205VII.F2.AP-204VII.F2.AP-205VII.F3.AP-204VII.F3.AP-205VII.F4.AP-204 

 51 BWR/PWR Boraflex spent fuel storage 

racks: neutron-absorbing sheets (PWR), spent fuel storage racks: neutronabsorbing sheets (BWR) exposed to treated borated water, treated water 

Reduction of neutron-absorbing capacity due to boraflex degradation 

AMP XI.M22, "Boraflex Monitoring" 

No VII.A2.A-86 

VII.A2.A-87 
3.3-30 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 52 BWR/PWR Steel cranes: rails and 

structural girders exposed to air – indoor uncontrolled, air – outdoor 

Loss of material due to general corrosion 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 

No VII.B.A-07 

M 53 BWR/PWR Steel cranes - rails exposed to 

air – indoor uncontrolled, air – outdoor 

Loss of material due to wear 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 

No VII.B.A-05 

M 54 BWR/PWR Copper alloy piping, piping 

components, exposed to condensation 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M24, "Compressed Air Monitoring" 

No VII.D.AP-240 

M 55 BWR/PWR Steel piping, piping 

components exposed to condensation (internal) 

Loss of material due to general, pitting corrosion 

AMP XI.M24, "Compressed Air Monitoring" 

No VII.D.A-26 

M 56 BWR/PWR Stainless steel piping, piping 

components, exposed to condensation (internal) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M24, "Compressed Air Monitoring" 

No VII.D.AP-81 

 57 BWR/PWR Elastomer fire barrier 

penetration seals exposed to air – indoor uncontrolled, air – outdoor 

Increased hardness; shrinkage; loss of strength due to weathering 

AMP XI.M26, "Fire Protection" 

No VII.G.A-19 

VII.G.A-20 
3.3-31 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 58 BWR/PWR Steel halon/carbon dioxide fire 

suppression system piping, piping components exposed to air – indoor uncontrolled (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M26, "Fire Protection" 

No VII.G.AP-150 

 59 BWR/PWR Steel fire rated doors exposed 

to air – indoor uncontrolled, air – outdoor 

Loss of material due to wear 

AMP XI.M26, "Fire Protection" 

No VII.G.A-21 

VII.G.A-22 

 60 BWR/PWR Reinforced concrete structural 

fire barriers: walls, ceilings and floors exposed to air – indoor uncontrolled 

Concrete cracking and spalling due to aggressive chemical attack, and reaction with aggregates 

AMP XI.M26, "Fire Protection," and AMP XI.S6, "Structures Monitoring" 

No VII.G.A-90 

 61 BWR/PWR Reinforced concrete structural 

fire barriers: walls, ceilings and floors exposed to air – outdoor 

Cracking, loss of material due to freeze- thaw, aggressive chemical attack, and reaction with aggregates 

AMP XI.M26, "Fire Protection," and AMP XI.S6, "Structures Monitoring" 

No VII.G.A-92 

 62 BWR/PWR Reinforced concrete structural 

fire barriers: walls, ceilings and floors exposed to air - indoor, uncontrolled, air – outdoor 

Loss of material due to corrosion of embedded steel 

AMP XI.M26, "Fire Protection," and AMP XI.S6, "Structures Monitoring" 

No VII.G.A-91 

VII.G.A-93 

 63 BWR/PWR Steel fire hydrants exposed to 

air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.AP-149 
3.3-32 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 64 BWR/PWR Steel, copper alloy piping, 

piping components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.A-33 

VII.G.AP-197 

M 65 BWR/PWR Aluminum piping, piping 

components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.AP-180 

M 66 BWR/PWR Stainless steel piping, piping 

components exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.A-55 

M 67 BWR/PWR Steel tanks exposed to air – 

outdoor (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

No 

VII.H1.A-95 

M 68 BWR/PWR Steel piping, piping 

components exposed to fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.G.AP-234 
3.3-33 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 69 BWR/PWR Copper alloy piping, piping 

components exposed to fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.G.AP-132 

VII.H1.AP-132VII.H2.AP-132 

M 70 BWR/PWR Steel piping, piping 

components, tanks exposed to fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.H1.AP-105

VII.H2.AP-105 

M 71 BWR/PWR Stainless steel, aluminum 

piping, piping components exposed to fuel oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M30, "Fuel Oil Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.G.AP-136 

VII.H1.AP-129VII.H1.AP-136VII.H2.AP-129VII.H2.AP-136 

M 72 BWR/PWR Gray cast iron, copper alloy 

(>15% Zn or >8% Al) piping, piping components, heat exchanger components exposed to treated water, closed-cycle cooling water, soil, raw water, waste water, ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VII.A3.AP-31 

VII.A3.AP-43 VII.A4.AP-31 VII.A4.AP-32 VII.A4.AP-43 VII.C1.A-02 VII.C1.A-47 VII.C1.A-51 VII.C1.A-66 VII.C2.A-50 VII.C2.AP-31 VII.C2.AP-32 VII.C2.AP-43 VII.C3.A-02 VII.C3.A-47 VII.C3.A-51 VII.E1.AP-31 
3.3-34 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.E1.AP-43 VII.E1.AP-65 VII.E3.AP-31 VII.E3.AP-32 VII.E3.AP-43 VII.E4.AP-31 VII.E4.AP-32 VII.E4.AP-43 VII.E5.A-547 VII.E5.A-724 VII.F1.AP-31 VII.F1.AP-43 VII.F1.AP-65 VII.F2.AP-31 VII.F2.AP-43 VII.F3.A-50 VII.F3.AP-43 VII.F3.AP-65 VII.F4.AP-31 VII.F4.AP-43 VII.G.A-02 VII.G.A-47 VII.G.A-51 VII.G.AP-31 VII.H1.A-02 VII.H1.AP-43 VII.H2.A-02 VII.H2.A-47 VII.H2.A-51 VII.H2.AP-43 

M 73 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to air – outdoor 

Changes in material properties due to aggressive chemical attack 

AMP XI.M36, "External Surfaces Monitoring of Mechanical 

No VII.C1.AP-253 
3.3-35 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Components" 

M 74 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to air – outdoor 

Cracking due to settling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.C1.AP-251 

M 75 BWR/PWR Reinforced concrete, asbestos 

cement piping, piping components exposed to air – outdoor 

Cracking due to aggressive chemical attack and leaching; changes in material properties due to aggressive chemical attack 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.C1.AP-156 

M 76 BWR/PWR Elastomer seals, piping, piping 

components exposed to air – indoor uncontrolled (internal/external), air – indoor controlled, outdoor air, dry air, condensation, air with borated water leakage 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.F1.AP-102

VII.F2.AP-102VII.F3.AP-102VII.F4.AP-102 

M 77 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to air – outdoor 

Loss of material due to abrasion, cavitation, aggressive chemical attack, leaching 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.C1.AP-252 

M 78 BWR/PWR Steel piping and components, 

ducting, closure bolting exposed to air – indoor uncontrolled, air – outdoor, 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of 

No VII.D.A-80 

VII.F1.A-10 VII.F1.A-105 VII.F2.A-10 
3.3-36 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

condensation Mechanical 

Components" 

VII.F2.A-105 VII.F3.A-10 VII.F3.A-105 VII.F4.A-10 VII.F4.A-105 VII.I.A-105 VII.I.A-77 VII.I.A-78 VII.I.A-81 

M 79 BWR/PWR Copper alloy piping, piping 

components, exposed to condensation (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No 

VII.I.AP-109 

M 80 BWR/PWR Steel heat exchanger 

components, piping, piping components, exposed to air – indoor uncontrolled (external), air – outdoor (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.F1.AP-41 

VII.F2.AP-41 VII.F3.AP-41 VII.F4.AP-41 VII.G.AP-40 VII.G.AP-41 VII.H1.A-24 VII.H2.AP-40 VII.H2.AP-41 

M 81 BWR/PWR Copper alloy, aluminum piping, 

piping components, exposed to air – outdoor (external), air – outdoor 

Loss of material due to general (copper alloy only) pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.AP-159 

VII.I.AP-256 

M 82 BWR/PWR Elastomer seals and 

components exposed to air – indoor uncontrolled (external), air – indoor controlled, outdoor air, dry air, air with borated 

Loss of material due to wear 

AMP XI.M36, "External Surfaces Monitoring of Mechanical 

No VII.I.AP-113 
3.3-37 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

water leakage Components" 

M 83 BWR/PWR Stainless steel diesel engine 

exhaust piping, piping components exposed to diesel exhaust 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.H2.AP-128 

M 85 BWR/PWR Elastomer seals, piping, piping 

components exposed to closed-cycle cooling water 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C2.AP-259 

M 86 BWR/PWR Elastomer seals piping and 

piping components exposed to treated borated water, treated water 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.A3.AP-100

VII.A4.AP-101 

M 88 BWR/PWR Steel; stainless steel piping 

and piping components, diesel engine exhaust exposed to raw water (potable), diesel exhaust 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

No VII.E5.AP-270

VII.H2.AP-104 
3.3-38 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Components" 

M 89 BWR/PWR Steel, copper alloy piping, 

piping components exposed to moist air, condensation (internal) 

Loss of material due to general, pitting, crevice corrosion 

For fire water system components: AMP XI.M27, "Fire Water System" 

No VII.G.AP-143 

 90 BWR/PWR Steel ducting and components 

(internal surfaces) exposed to condensation (internal) 

Loss of material due to general, pitting, crevice corrosion, (for drip pans and drain lines) MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.A-08 

VII.F2.A-08 VII.F3.A-08 VII.F4.A-08 

M 91 BWR/PWR Steel piping, piping 

components, tanks exposed to waste water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-281 

M 92 BWR/PWR Aluminum piping, piping 

components, exposed to condensation (internal) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.AP-142

VII.F2.AP-142VII.F3.AP-142VII.F4.AP-142 
3.3-39 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 93 BWR/PWR Copper alloy piping, piping 

components, exposed to raw water (potable) 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-271 

 94 BWR/PWR Stainless steel ducting and 

components exposed to condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.AP-99 

VII.F2.AP-99 VII.F3.AP-99 

M 95 BWR/PWR Copper alloy, stainless steel, 

aluminum, nickel alloy, steel piping, piping components, heat exchanger components, piping, piping components, tanks exposed to waste water, condensation (internal) 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC (steel, stainless steel, nickel alloy, and copper alloy in waste water environments only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.AP-272

VII.E5.AP-273VII.E5.AP-274VII.E5.AP-275VII.E5.AP-276VII.E5.AP-278VII.E5.AP-279VII.E5.AP-280 

M 96 BWR/PWR Elastomer seals, piping, piping 

components exposed to air – indoor uncontrolled (internal) 

Loss of material due to wear 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.AP-103

VII.F2.AP-103VII.F3.AP-103VII.F4.AP-103 
3.3-40 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 96.2 BWR/PWR Steel, aluminum, copper alloy, 

stainless steel heat exchanger tubes exposed to condensation (for components not covered by NRC GL 89-13) 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-419 

VII.F1.A-419 VII.F2.A-419 VII.F3.A-419 VII.F4.A-419 

N 96.4 BWR/PWR Steel, aluminum, copper alloy, 

stainless steel heat exchanger components exposed to condensation (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion; fouling that leads to corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-417 

VII.C1.A-418 VII.F1.A-417 VII.F1.A-418 VII.F2.A-417 VII.F2.A-418 VII.F3.A-417 VII.F3.A-418 VII.F4.A-417 VII.F4.A-418 

M 97 BWR/PWR Steel piping, piping 

components, reactor coolant pump oil collection system: tanks, reactor coolant pump oil collection system: piping, tubing, valve bodies exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-127

VII.C2.AP-127VII.E1.AP-127VII.E4.AP-127VII.F1.AP-127VII.F2.AP-127VII.F3.AP-127VII.F4.AP-127VII.G.AP-116 VII.G.AP-117 VII.G.AP-127 VII.H2.AP-127 

 98 BWR/PWR Steel heat exchanger 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time 

No VII.H2.AP-131 
3.3-41 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

to corrosion Inspection" 

M 99 BWR/PWR Copper alloy, aluminum piping, 

piping components exposed to lubricating oil 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC (copper alloy only) 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-133

VII.C2.AP-133VII.E1.AP-133VII.E4.AP-133VII.G.AP-133 VII.H2.AP-133VII.H2.AP-162 

M 100 BWR/PWR Stainless steel piping, piping 

components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.C1.AP-138

VII.C2.AP-138VII.E1.AP-138VII.E4.AP-138VII.G.AP-138 VII.H2.AP-138 

 101 BWR/PWR Aluminum heat exchanger 

tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VII.H2.AP-154 

 102 BWR/PWR Boral®; boron steel, and other 

materials (excluding Boraflex) spent fuel storage racks: neutron-absorbing sheets (PWR), spent fuel storage racks: neutron-absorbing sheets (BWR) exposed to treated borated water, treated water 

Reduction of neutron-absorbing capacity; change in dimensions and loss of material due to effects of SFP environment 

AMP XI.M40, "Monitoring of NeutronAbsorbing Materials other than Boraflex" 

No VII.A2.AP-235

VII.A2.AP-236 
3.3-42 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 103 BWR/PWR Reinforced concrete, asbestos 

cement piping, piping components exposed to soil, concrete 

Cracking due to aggressive chemical attack and leaching; Changes in material properties due to aggressive chemical attack 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-157 

M 104 BWR/PWR HDPE, fiberglass piping, piping 

components exposed to soil, concrete 

Cracking, blistering, change in color due to water absorption 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-175

VII.C1.AP-176 

M 105 BWR/PWR Concrete, concrete cylinder 

piping, asbestos cement pipe piping, piping components exposed to soil, concrete 

Cracking, spalling, corrosion of rebar due to exposure of rebar 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-177

VII.C1.AP-178VII.C1.AP-237 

M 106 BWR/PWR Steel (with coating or 

wrapping) piping, piping components exposed to soil, concrete 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-198

VII.C3.AP-198VII.G.AP-198 VII.H1.AP-198 

M 107 BWR/PWR Stainless steel, nickel alloy 

piping, piping components exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-137

VII.C3.AP-137VII.G.AP-137 VII.H1.AP-137VII.H2.AP-137 

M 108 BWR/PWR Titanium, super austenitic, 

aluminum, copper alloy, stainless steel, nickel alloy piping, piping components, bolting exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.AP-171

VII.C1.AP-172VII.C1.AP-173VII.C1.AP-174VII.I.AP-243 
3.3-43 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 109 BWR/PWR Steel bolting exposed to soil, 

concrete 

Loss of material due to general, pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-241 

M 109a BWR/PWR Copper alloy, stainless steel, 

nickel alloy, steel underground piping, piping components exposed to air – indoor uncontrolled, condensation, air – outdoor (external) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.AP-284 

M 110 BWR Stainless steel piping, piping 

components exposed to treated water >60°C (>140°F) 

Cracking due to stress corrosion cracking, intergranular stress corrosion cracking 

AMP XI.M7, "BWR Stress Corrosion Cracking," and AMP XI.M2, "Water Chemistry" 

Yes (SRP-SLR Section 3.3.2.2.9) 

VII.E4.A-61 

 111 BWR/PWR Steel structural steel exposed 

to air – indoor uncontrolled (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No VII.A1.A-94 

M 112 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.3.2.2.11) 

VII.J.AP-282 

M 113 BWR/PWR Aluminum piping, piping 

components exposed to gas 

None None No VII.J.AP-37 

M 114 BWR/PWR Copper alloy piping, piping 

components exposed to air – indoor uncontrolled (internal/external), air – dry, 

None None No VII.J.AP-144 

VII.J.AP-8 VII.J.AP-9 
3.3-44 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

gas 

M 115 PWR Copper alloy piping, piping 

components exposed to air with borated water leakage 

None None No VII.J.AP-11 

M 116 BWR/PWR Galvanized steel piping, piping 

components exposed to air – indoor uncontrolled 

None None No VII.J.AP-13 

M 117 BWR/PWR Glass piping elements exposed 

to air, air – indoor uncontrolled (external), lubricating oil, closed-cycle cooling water, air – outdoor, fuel oil, raw water, treated water, treated borated water, air with borated water leakage, condensation (internal/external), gas 

None None No VII.J.AP-14 

VII.J.AP-15 VII.J.AP-166 VII.J.AP-167 VII.J.AP-48 VII.J.AP-49 VII.J.AP-50 VII.J.AP-51 VII.J.AP-52 VII.J.AP-96 VII.J.AP-97 VII.J.AP-98 

M 118 BWR/PWR Nickel alloy piping, piping 

components exposed to air – indoor uncontrolled (external) 

None None No VII.J.AP-16 

M 119 BWR/PWR Nickel alloy, PVC, glass piping, 

piping components exposed to air with borated water leakage, air – indoor uncontrolled, condensation (internal), waste water, potable water, raw water 

None None No VII.J.AP-260 

VII.J.AP-268 VII.J.AP-269 VII.J.AP-277 
3.3-45 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 120 BWR/PWR Stainless steel piping, piping 

components exposed to air – indoor uncontrolled (internal/external), air – indoor uncontrolled (external), air with borated water leakage, air – dry, gas 

None None No VII.J.AP-123 

VII.J.AP-17 VII.J.AP-18 VII.J.AP-20 VII.J.AP-22 

M 121 BWR/PWR Steel piping, piping 

components, exposed to air – indoor controlled (external), air – dry, gas 

None None No VII.J.AP-2 

VII.J.AP-4 VII.J.AP-6 

M 122 BWR/PWR Titanium heat exchanger 

components, piping and piping components exposed to air – indoor uncontrolled, air – outdoor 

None None No VII.J.AP-151 

VII.J.AP-160 

M 123 BWR/PWR Titanium (ASTM Grades 1,2, 7, 

11, or 12) heat exchanger components other than tubes, piping and piping components exposed to raw water 

None None No VII.C1.AP-152

VII.C1.AP-161 

M 124 BWR/PWR Stainless steel, steel (with 

stainless steel or nickel-alloy cladding) spent fuel storage racks (BWR), spent fuel storage racks (PWR), piping, piping components exposed to treated water >60°C (>140°F), treated borated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.A2.A-96 

VII.A2.A-97 VII.A3.A-56 VII.E1.A-103 

M 125 BWR/PWR Steel (with stainless steel 

cladding); stainless steel spent fuel storage racks (BWR), spent fuel storage racks (PWR), piping, piping 

Loss of material due to pitting, crevice corrosion, MIC 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.12) 

VII.A2.AP-79 VII.A3.AP-79 VII.E1.AP-79 VII.A2.A-98 VII.A2.A-99 
3.3-46 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

components exposed to treated water, treated borated water 

M 126 BWR/PWR Any material piping, piping 

components exposed to treated water, treated borated water, raw water 

Wall thinning due to erosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No VII.C1.A-409 

VII.E1.A-407 VII.E3.A-408 

M 127 BWR/PWR Metallic piping, piping 

components, tanks exposed to raw water, waste water 

Loss of material due to recurring internal corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.7) 

VII.A2.A-400 VII.A3.A-400 VII.A4.A-400 VII.C1.A-400 VII.C2.A-400 VII.C3.A-400 VII.D.A-400 VII.E1.A-400 VII.E2.A-400 VII.E3.A-400 VII.E4.A-400 VII.E5.A-400 VII.F1.A-400 VII.F2.A-400 VII.F3.A-400 VII.F4.A-400 VII.G.A-400 VII.H1.A-400 VII.H2.A-400 

M 128 BWR/PWR Steel tanks (within the scope of 

AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete, air – outdoor, air – indoor uncontrolled, moist air, raw water, condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (soil, raw water environments only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.C3.A-401 

VII.E5.A-401 VII.H1.A-401 
3.3-47 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 129 BWR/PWR Steel tanks exposed to soil, 

concrete; air – indoor uncontrolled, raw water, treated water, waste water, condensation 

Loss of material due to general, pitting, crevice corrosion, MIC (soil, raw water, treated water, waste water environments only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.H1.A-402 

M 130 BWR/PWR Metallic sprinklers exposed to 

air – indoor controlled, air – indoor uncontrolled, air – outdoor, moist air, condensation, raw water, treated water 

Loss of material due to general, pitting, crevice corrosion, MIC (raw water and treated water environments only and all metals except for aluminum only), fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.A-403 

M 131 BWR/PWR Steel, stainless steel, copper 

alloy, aluminum piping, piping components exposed to air – indoor uncontrolled (internal), air – outdoor (internal), condensation (internal) 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion, fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M27, "Fire Water System" 

No VII.G.A-404 

M 132 BWR/PWR Insulated steel, copper alloy, 

copper alloy (> 15% Zn), aluminum piping, piping components, tanks exposed to 

Loss of material due to general (steel, copper alloy only), pitting, 

AMP XI.M36, "External Surfaces Monitoring of 

No VII.I.A-405 
3.3-48 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

condensation, air – outdoor crevice corrosion; 

cracking due to stress corrosion cracking (copper alloy (>15% Zn) only) 

Mechanical Components" 

M 133 BWR/PWR HDPE underground piping, 

piping components exposed to air – indoor uncontrolled, condensation, air – outdoor (external) 

Cracking, blistering, change in color due to water absorption 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.A-406 

M 134 BWR/PWR Steel, stainless steel, copper 

alloy piping, piping components, and heat exchanger components exposed to a raw water environment (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC, fouling that leads to corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-727 

 135 BWR/PWR Steel, stainless steel pump 

casings submerged in a waste water (internal and external) environment 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.E5.A-410 

VII.E5.A-411 

M 136 BWR/PWR Steel fire water storage tanks 

exposed to air – indoor uncontrolled, air – outdoor, condensation, moist air, raw water, treated water, soil, concrete 

Loss of material due to general, pitting, crevice corrosion, MIC (raw water, treated water, soil only), fouling that leads to corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.A-412 
3.3-49 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

M 137 BWR/PWR Steel, stainless steel, 

aluminum tanks (within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to treated water, treated borated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.C3.A-413 

VII.E5.A-413 VII.H1.A-413 

M 138 BWR/PWR Any material piping, piping 

components, heat exchangers, tanks with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, treated borated water, waste water, lubricating oil, fuel oil 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage, and spalling for cementitious coatings/linings 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.A2.A-416 

VII.A3.A-416 VII.A4.A-416 VII.C1.A-416 VII.C2.A-416 VII.C3.A-416 VII.D.A-416 VII.E1.A-416 VII.E2.A-416 VII.E3.A-416 VII.E4.A-416 VII.E5.A-416 VII.F1.A-416 VII.F2.A-416 VII.F3.A-416 VII.F4.A-416 VII.G.A-416 VII.H1.A-416 VII.H2.A-416 

M 139 BWR/PWR Any material piping, piping 

components, heat exchangers, tanks with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, treated borated water, lubricating oil, waste water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; cracking due to stress corrosion cracking 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.A2.A-414 

VII.A3.A-414 VII.A4.A-414 VII.C1.A-414 VII.C2.A-414 VII.C3.A-414 VII.D.A-414 VII.E1.A-414 VII.E2.A-414 VII.E3.A-414 
3.3-50 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.E4.A-414 VII.E5.A-414 VII.F1.A-414 VII.F2.A-414 VII.F3.A-414 VII.F4.A-414 VII.G.A-414 VII.H1.A-414 VII.H2.A-414 

M 140 BWR/PWR Gray cast iron piping 

components with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, waste water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VII.C1.A-415 

VII.C2.A-415 VII.C3.A-415 VII.D.A-415 VII.E1.A-415 VII.E2.A-415 VII.E3.A-415 VII.E4.A-415 VII.E5.A-415 VII.F1.A-415 VII.F2.A-415 VII.F3.A-415 VII.F4.A-415 VII.G.A-415 VII.H1.A-415 VII.H2.A-415 

N 141 BWR/PWR Steel, stainless steel bolting 

exposed to condensation, fuel oil, lubricating oil 

Loss of preload due to thermal effects, gasket creep, or selfloosening 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-421 

VII.I.A-422 

N 142 BWR/PWR Copper alloy bolting exposed 

to raw water, waste water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-423 
3.3-51 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 143 BWR/PWR Steel bolting exposed to 

lubricating oil, fuel oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-424 

N 144 BWR/PWR Stainless steel, aluminum 

piping, piping components exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.A-425 

VII.C3.A-425 VII.E5.A-425 VII.G.A-425 VII.H1.A-425 VII.H2.A-425 

N 145 BWR/PWR Stainless steel bolting exposed 

to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.A-426 

VII.C3.A-426 VII.E5.A-426 VII.G.A-426 VII.H1.A-426 VII.H2.A-426 

N 146 BWR/PWR Stainless steel underground 

piping, piping components, tanks exposed to air – outdoor, raw water, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.C1.A-714 VII.C2.A-714 VII.C3.A-714 VII.D.A-714 VII.E1.A-714 VII.E4.A-714 VII.F1.A-714 VII.F2.A-714 VII.F4.A-714 VII.G.A-714 VII.H1.A-714 VII.H2.A-714 

N 147 BWR/PWR Nickel alloy and nickel alloy 

cladding piping, piping components exposed to closed cycle cooling water, closed cycle cooling water >60°C (>140°F) 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-471 
3.3-52 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 148 BWR/PWR Elastomer piping, ducting 

components exposed to air – outdoor 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-427 

N 149 BWR/PWR Fiberglass piping and ducting, 

piping and ducting components exposed to air – outdoor 

Cracking, blistering, change in color due to water absorption 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-428 

N 150 BWR/PWR Fiberglass piping and ducting, 

piping and ducting components exposed to air – indoor 

Change in material properties due to exposure to ultraviolet light, ozone, radiation, temperature 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-720 

N 151 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components exposed to air, condensation (external) 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-716 

N 153 BWR/PWR Elastomer seals, piping, piping 

components exposed to air – outdoor 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-708 

N 154 BWR/PWR Elastomer, fiberglass piping, 

piping components, ducting, ducting components exposed to air-outdoor, air-indoor 

Loss of material due to wear 

AMP XI.M36, "External Surfaces Monitoring of Mechanical 

No VII.I.A-719 
3.3-53 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Components" 

N 155 BWR/PWR Stainless steel piping, piping 

components, and tanks exposed to waste water greater than 140° F 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E5.A-721 

N 156 BWR/PWR Elastomer seals, piping, piping 

components exposed to condensation, waste water, gas, fuel oil, lubricating oil 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E1.A-504 

VII.E2.A-504 VII.E3.A-504 VII.E4.A-504 VII.E5.A-504 VII.F1.A-504 VII.F2.A-504 VII.F3.A-504 VII.F4.A-504 VII.G.A-504 VII.H1.A-660 VII.H2.A-677 VII.E5.A-728 VII.D.A-729 

N 157 BWR/PWR Steel piping, piping 

components, heat exchanger components exposed to air-outdoor (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.E1.A-722 

VII.E2.A-722 VII.E3.A-722 VII.E4.A-722 VII.E5.A-722 VII.F1.A-722 VII.F2.A-722 VII.F3.A-722 VII.F4.A-722 
3.3-54 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.G.A-722 VII.H1.A-722 VII.H2.A-722 

N 158 BWR/PWR Nickel alloy piping, piping 

components heat exchanger components (for components not covered by NRC GL 89-13) exposed to raw water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-454 

VII.C2.A-454 

N 159 BWR/PWR Fiberglass piping, piping 

components, ducting and components exposed to air – indoor (internal) 

Loss of material due to wear 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.D.A-495 

VII.E5.A-495 VII.F1.A-495 VII.F2.A-495 VII.F3.A-495 VII.F4.A-495 VII.G.A-495 VII.H1.A-495 VII.H2.A-495 

N 160 BWR/PWR Copper alloy (>15% Zn or >8% 

Al) piping, piping components, heat exchanger components exposed to closed-cycle cooling water 

Cracking due to stress corrosion cracking 

AMP XI.M21A, "Closed Treated Water Systems" 

No VII.C2.A-473 

N 161 BWR/PWR Copper alloy heat exchanger 

components exposed to condensation 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.F1.A-565 

VII.F2.A-565 VII.F3.A-565 VII.F4.A-565 VII.G.A-565 VII.H1.A-565 VII.H2.A-565 
3.3-55 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 162 BWR/PWR Steel, stainless steel, copper 

alloy piping, piping components exposed to air-outdoor 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.A-637 

N 164 BWR/PWR Gray cast iron piping, piping 

components exposed to air – indoor uncontrolled, air – outdoor, moist air, condensation, raw water, treated water, waste water (external) 

Loss of material due to general, pitting, crevice corrosion, MIC (raw water, waste water, and treated water environments only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No 

VII.I.A-455 

N 165 BWR/PWR Gray cast iron piping, piping 

components exposed to air – indoor uncontrolled, air – outdoor, moist air, condensation, raw water, treated water, waste water (internal) 

Loss of material due to general, pitting, crevice corrosion, MIC (raw water, waste water, and treated water environments only) 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-456 

VII.C2.A-456 VII.C3.A-456 VII.D.A-456 VII.E5.A-456 VII.G.A-456 VII.H1.A-456 VII.H2.A-456 

N 166 BWR/PWR Copper alloy piping, piping 

components exposed to concrete 

None None No VII.J.A-711 

N 167 BWR/PWR Zinc piping components 

exposed to air-indoor 

None None No VII.J.A-712 

N 169 BWR/PWR Steel, copper alloy piping, 

piping components exposed to steam 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-566 

VII.F2.A-566 VII.F3.A-566 VII.F4.A-566 
3.3-56 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 170 BWR/PWR Stainless steel piping, piping 

components exposed to steam 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-567 

VII.F2.A-567 VII.F3.A-567 VII.F4.A-567 

N 171 BWR/PWR Steel, stainless steel bolting 

exposed to raw water, waste water, treated water, treated borated water 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No VII.I.A-725 

VII.I.A-723 VII.I.A-726 

N 172 BWR/PWR PVC piping, piping 

components exposed to sunlight 

Reduction in impact strength due to photolysis 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.8) 

VII.C1.A-458 VII.E5.A-458 VII.G.A-458 

N 173 BWR/PWR Elastomer seals, piping, piping 

components exposed to raw water, raw water (for components not covered by NRC GL 89-13), waste water, treated water, fuel oil, lubricating oil, condensation 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-457 

VII.C2.A-477 VII.D.A-498 VII.E5.A-548 VII.G.A-641 VII.H1.A-667 VII.H2.A-667 VII.A2.A-749 VII.A3.A-749 VII.A4.A-749 VII.C1.A-749 VII.C2.A-749 VII.C3.A-749 VII.D.A-749 VII.E1.A-749 VII.E2.A-749 VII.E3.A-749 VII.E4.A-749 VII.E5.A-749 VII.F1.A-749 VII.F2.A-749 
3.3-57 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.F3.A-749 VII.F4.A-749 VII.G.A-749 VII.H1.A-749 VII.H2.A-749 

N 174 BWR/PWR Elastomer seals, piping, piping 

components exposed to raw water, raw water (for components not covered by NRC GL 89-13), waste water 

Loss of material due to wear 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-459 

VII.E5.A-550 

N 175 BWR/PWR Fiberglass piping, piping 

components, tanks exposed to raw water, raw water (for components not covered by NRC GL 89-13), waste water 

Cracking, blistering, change in color due to water absorption 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-460 

VII.E5.A-551 VII.G.A-644 

N 176 BWR/PWR Fiberglass piping, piping 

components, tanks exposed to raw water, raw water environment (for components not covered by NRC GL 89-13), waste water 

Loss of material due to wear 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-461 

VII.E5.A-552 VII.G.A-645 

N 177 BWR/PWR Fiberglass piping, piping 

components exposed to soil 

Loss of material due to wear 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.C1.A-462 

VII.E5.A-462 VII.G.A-462 
3.3-58 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 178 BWR/PWR Fiberglass piping and piping 

components exposed to concrete 

None None No VII.J.A-710 

N 179 BWR/PWR Masonry walls: structural fire 

barriers exposed to air – indoor uncontrolled, air – outdoor 

Cracking due to restraint shrinkage, creep, aggressive environment 

AMP XI.M26, "Fire Protection," and AMP XI.S5, "Masonry Walls" 

No VII.G.A-626 

N 180 BWR/PWR Masonry walls: structural fire 

barriers exposed to air – outdoor 

Loss of material (spalling, scaling) and cracking due to freeze-thaw 

AMP XI.M26, "Fire Protection," and AMP XI.S5, "Masonry Walls" 

No VII.G.A-627 

N 181 BWR/PWR Stainless steel, nickel alloy, 

aluminum, titanium piping, piping components, exposed to condensation (External) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-700 

VII.I.A-701 VII.I.A-702 VII.I.A-703 

N 182 BWR/PWR Jacketed thermal insulation in 

an air – indoor uncontrolled, air – outdoor environment, air with borated water leakage, air with reactor coolant leakage, air with steam or water leakage 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.I.A-704 

N 184 BWR/PWR PVC piping, piping 

components, tanks exposed to concrete 

None None No VII.J.A-709 

N 185 BWR/PWR Aluminum fire water storage 

tanks exposed to air – outdoor, raw water, condensation, soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M27, "Fire Water System" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.G.A-623 
3.3-59 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 186 BWR/PWR Aluminum tanks (within the 

scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – indoor controlled, air – indoor uncontrolled, raw water, waste water, condensation, soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.C3.A-482 VII.E5.A-482 VII.H1.A-482 

N 187 BWR/PWR Insulated aluminum tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – indoor controlled, air – indoor uncontrolled, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.G.A-654 VII.H1.A-654 

N 189 BWR/PWR Aluminum tanks, piping, piping 

components exposed to air – outdoor, raw water, waste water, condensation (internal) 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.A2.A-429 VII.A3.A-429 VII.A4.A-429 VII.C1.A-451 VII.C2.A-451 VII.C3.A-451 VII.D.A-451 VII.E1.A-451 VII.E2.A-451 VII.E3.A-451 VII.E4.A-451 VII.E5.A-451 VII.F1.A-451 VII.F2.A-451 VII.F3.A-451 VII.F4.A-451 VII.G.A-451 VII.H1.A-451 VII.H2.A-451 
3.3-60 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 190 BWR/PWR Aluminum piping, piping 

components, tanks exposed to raw water, waste water, condensation (external) 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-452 

N 191 BWR/PWR Aluminum piping, piping 

components, tanks exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.I.A-707 

N 192 BWR/PWR Aluminum underground piping, 

piping components, tanks exposed to air – outdoor, raw water, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-706 

N 193 BWR/PWR Steel components exposed to 

treated water, raw water, waste water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "One-Time Inspection" 

No VII.A4.A-439 

VII.C1.A-469 VII.E1.A-439 VII.E3.A-439 VII.E4.A-532 VII.E5.A-469 VII.G.A-651 VII.H2.A-651 

N 194 BWR/PWR PVC piping, piping 

components, and tanks exposed to soil, concrete 

Loss of material due to wear 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VII.E5.A-537 

VII.G.A-537 

N 195 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water 

Changes in material properties due to aggressive chemical attack 

AMP XI.M27, "Fire Water System" 

No VII.G.A-647 
3.3-61 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 196 BWR/PWR HDPE piping, piping 

components exposed to raw water 

Cracking, blistering, change in color due to water absorption 

AMP XI.M27, "Fire Water System" 

No VII.G.A-648 

N 197 BWR/PWR Fire water system piping, 

piping components, heat exchanger, heat exchanger components (any material) with only a leakage boundary (spatial) or structural integrity (attached) intended function 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VII.G.A-649 

N 198 BWR/PWR Fire water system piping, 

piping components, heat exchanger, heat exchanger components (any material) with only a leakage boundary (spatial) or structural integrity (attached) intended function 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC, fouling that leads to corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.G.A-650 

N 199 BWR/PWR Steel structural bolting 

exposed to air – indoor uncontrolled, air – outdoor 

Loss of preload due to selfloosening 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 

No VII.B.A-730 

N 200 BWR/PWR High-strength steel structural 

bolting exposed to air – indoor uncontrolled, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

No VII.B.A-731 
3.3-62 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Handling Systems" 

N 202 BWR/PWR Stainless steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.3.2.2.11) 

VII.J.AP-19 

N 203 BWR Stainless steel; steel with 

stainless steel cladding, piping, piping components, heat exchanger components exposed to treated water, sodium pentaborate solution 

Loss of material due to pitting, crevice corrosion, MIC 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.12) 

VII.A4.AP-110VII.E3.AP-110VII.E4.AP-110VII.A4.AP-111VII.E2.AP-141 

N 204 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components internal to components exposed to air (external), condensation 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-733 

VII.C2.A-733 VII.D.A-733 VII.F1.A-733 VII.F2.A-733 VII.F3.A-733 VII.F4.A-733 VII.H2.A-733 

N 205 BWR/PWR Insulated stainless steel piping, 

piping components, tanks exposed to air – indoor uncontrolled, air – indoor controlled, condensation, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.I.A-734 

N 206 PWR Copper alloy (≤8% Al) piping, 

piping components exposed to air with borated water leakage 

None None No VII.J.A-735 

N 207 BWR/PWR Stainless steel, copper alloy, 

titanium heat exchanger tubes exposed to raw water (for 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal 

No VII.C1.A-736 
3.3-63 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

components not covered by NRC GL 89-13) 

Surfaces in Miscellaneous Piping and Ducting Components" 

N 208 BWR/PWR Reinforced concrete, asbestos 

cement piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Cracking due to aggressive chemical attack and leaching; changes in material properties due to aggressive chemical attack 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-737 

N 209 BWR/PWR Fiberglass piping, piping 

components exposed to raw water (internal) (for components not covered by NRC GL 89-13) 

Cracking, blistering, change in color due to water absorption 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-738 

N 210 BWR/PWR HDPE piping, piping 

components exposed to raw water (internal) (for components not covered by NRC GL 89-13) 

Cracking, blistering, change in color due to water absorption 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-739 

N 211 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Cracking due to settling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and 

No VII.C1.A-740 
3.3-64 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

Ducting Components" 

N 212 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to abrasion, cavitation, aggressive chemical attack, leaching 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-741 

N 213 BWR/PWR Concrete, cementitious 

material piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Changes in material properties due to aggressive chemical attack 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.C1.A-742 

N 214 BWR/PWR Copper alloy (>15% Zn or >8% 

Al) piping, piping components exposed to soil ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VII.C1.A-743 

VII.C2.A-743 VII.C3.A-743 VII.D.A-743 VII.E4.A-743 VII.E5.A-743 VII.G.A-743 VII.H1.A-743 VII.H2.A-743 

N 215 BWR/PWR Aluminum fire water storage 

tanks exposed to air – indoor uncontrolled, air – outdoor, condensation, moist air, raw water, treated water, soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

No VII.G.A-744 
3.3-65 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

N 216 BWR/PWR Stainless steel fire water 

storage tanks exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M27, "Fire Water System" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.G.A-745 

N 217 BWR/PWR Stainless steel fire water 

storage tanks exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M27, "Fire Water System" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.G.A-746 

N 218 BWR/PWR Stainless steel fire water 

storage tanks exposed to air – indoor uncontrolled, condensation, moist air, raw water, treated water, soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M27, "Fire Water System" 

No VII.G.A-747 

N 219 BWR/PWR Stainless steel piping, piping 

components exposed to steam 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VII.F1.A-748 

VII.F2.A-748 VII.F3.A-748 VII.F4.A-748 

M 220 BWR/PWR Steel, copper alloy piping, 

piping components exposed to moist air, condensation (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VII.H2.A-23 

N 221 BWR/PWR Aluminum piping, piping 

components exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.C1.A-750 VII.C2.A-750 VII.C3.A-750 VII.D.A-750 VII.E1.A-750 VII.E4.A-750 VII.F1.A-750 
3.3-66 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

VII.F2.A-750 VII.F4.A-750 VII.G.A-750 VII.H1.A-750 VII.H2.A-750 

N 222 BWR/PWR Stainless steel tanks exposed 

to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.I.A-751 

N 223 BWR/PWR Aluminum underground piping, 

piping components exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.13) 

VII.I.A-752 

N 224 BWR/PWR Aluminum piping, piping 

components exposed to air – outdoor (external) 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-753 

N 225 BWR/PWR Aluminum tanks exposed to air 

– outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-754 

N 226 BWR/PWR Aluminum tanks (within the 

scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.C3.A-755 

VII.E5.A-755 VII.H1.A-755 

N 227 BWR/PWR Aluminum tanks (within the 

scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.13) 

VII.C3.A-756 VII.E5.A-756 VII.H1.A-756 

N 228 BWR/PWR Stainless steel tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – 

Loss of material due to pitting, crevice corrosion, MIC (raw water 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.C3.A-757 VII.E5.A-757 VII.H1.A-757 
3.3-67 

Table 3.3-1. Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report 

New (N), 

Modified (M), 

Deleted (D) 

Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended

GALL-SLR 

Item 

indoor uncontrolled, moist air, raw water, condensation 

environment only) 

N 229 BWR/PWR Stainless steel tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, ground water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.C3.A-758 

VII.E5.A-758 VII.H1.A-758 

N 230 BWR/PWR Stainless steel tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VII.C3.A-759 

VII.E5.A-759 VII.H1.A-759 

N 231 BWR/PWR Stainless steel tanks (within 

the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – indoor uncontrolled, air – indoor controlled, condensation 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.3.2.2.3) 

VII.C3.A-760 VII.E5.A-760 VII.H1.A-760 

N 232 BWR/PWR Insulated stainless steel piping, 

piping components, tanks exposed to condensation, air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.4) 

VII.I.A-761 

N 233 BWR/PWR Insulated aluminum piping, 

piping components, tanks exposed to condensation, air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.3.2.2.10) 

VII.I.A-762 

N 234 BWR/PWR Aluminum piping, piping 

components exposed to air – dry, air– indoor uncontrolled, air– indoor controlled 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.3.2.2.13 

VII.J.A-763 
3.3-68 

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

Management of Auxiliary Systems 

GALL-SLR Report 

Chapter/AMP Program Name 

AMP XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD 

AMP XI.M2 Water Chemistry 

AMP XI.M7 Boiling Water Reactor Stress Corrosion Cracking 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M22 Boraflex Monitoring 

AMP XI.M23 Inspection of Overhead Heavy and Light Loads (Related to 

Refueling) Handling Systems 

AMP XI.M24 Compressed Air Monitoring 

AMP XI.M25 Boiling Water Reactor Cleanup System 

AMP XI.M26 Fire Protection 

AMP XI.M27 Fire Water System 

AMP XI.M29 Aboveground Metallic Tanks 

AMP XI.M30 Fuel Oil Chemistry 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M40 Monitoring of Neutron-Absorbing Materials Other than Boraflex

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In Scope Piping, Piping 

Components, Heat Exchangers, and Tanks 

AMP XI.S6 Structures Monitoring 

Appendix for GALL-SLR Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 
3.4-1 

1 3.4 Aging Management of Steam and Power Conversion System 

2 Review Responsibilities 

3 Primary—Branch assigned responsibility by Project Manager (PM) as described in Section 3.0 

4 of this Standard Review Plan for Review of Subsequent License Renewal Applications for 

5 Nuclear Power Plants (SRP-SLR). 

6 3.4.1 Areas of Review 

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

8 management programs (AMPs) of the steam and power conversion system. For a recent 

9 vintage plant, the information related to the steam and power conversion system is contained in 

10 Chapter 10, “Steam and Power Conversion System,” of the plant’s Final Safety Analysis Report 

11 (FSAR), consistent with the “Standard Review Plan for the Review of Safety Analysis Reports 

12 for Nuclear Power Plants” (NUREG–0800). The steam and power conversion systems 

13 contained in this review plan section are generally consistent with those contained in 

14 NUREG–0800 except for the condenser circulating water and the condensate storage systems. 

15 For older plants, the location of applicable information is plant-specific because an older plant’s 

16 FSAR may have predated NUREG–0800. 

17 Typical steam and power conversion systems that are subject to an AMR for subsequent 

18 license renewal (SLR) are steam turbine, main steam, extraction steam, feedwater, condensate, 

19 steam generator blowdown, and auxiliary feedwater (AFW). This review plan section also 

20 includes structures and components (SCs) in nonsafety-related systems that are not connected 

21 to safety-related systems, structures, and components (SSCs) but have a spatial relationship 

22 such that their failure could adversely impact the performance of a safety-related SSC-intended 

23 function. Examples of such nonsafety-related systems may be extraction steam, plant heating 

24 steam/auxiliary boilers and hot water heating systems. 

25 The aging management for the steam generator is reviewed following the guidance in 

26 Section 3.1 of this SRP-SLR. The aging management for portions of the boiling water reactor 

27 (BWR) main steam and main feedwater systems, extending from the reactor vessel to the 

28 outermost containment isolation valve, is reviewed separately following the guidance in 

29 Section 3.1 of this SRP-SLR. 

30 The responsible review organization is to review the following subsequent license renewal 

31 application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 3.0: 

32 AMRs 

33  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

34 License Renewal (GALL-SLR) Report 

35  AMR results for which further evaluation is recommended 

36  AMR results not consistent with or not addressed in the GALL-SLR Report 
3.4-2 

1 AMPs 

2  Consistent with the GALL-SLR Report AMPs 

3  Plant-specific AMPs 

4 FSAR Supplement 

5  The responsible review organization is to review the FSAR Supplement associated with 

6 each assigned AMP. 

7 3.4.2 Acceptance Criteria 

8 The acceptance criteria for the areas of review describe methods for determining whether the 

9 applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

10 regulations in 10 CFR 54.21. 

11 3.4.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

12 Learned for Subsequent License Renewal Report 

13 The AMR and the AMPs applicable to the steam and power conversion system are described 

14 and evaluated in Chapter VIII of the GALL-SLR Report. 

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

16 confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

17 cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item 

18 is consistent with the GALL-SLR Report AMR item to which it is compared. 

19 When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, 

20 the reviewer should confirm that the alternate AMP is valid to use for aging management and 

21 will be capable of managing the effects of aging as adequately as the AMP recommended by 

22 the GALL-SLR Report. 

23 3.4.2.2 Aging Management Review Results for Which Further Evaluation Is 

24 Recommended by the Generic Aging Lessons Learned for Subsequent License 

25 Renewal Report 

26 The basic acceptance criteria, defined in Subsection 3.4.2.1, need to be applied first for all of 

27 the AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR 

28 item to which the SLRA AMR item is compared identifies that “further evaluation is 

29 recommended,” then additional criteria apply as identified by the GALL-SLR Report for each of 

30 the following aging effect/aging mechanism combinations. Refer to Table 3.4-1, comparing the 

31 “Further Evaluation Recommended” and the “GALL-SLR Item” column, for the AMR items that 

32 reference the following subsections. 

33 3.4.2.2.1 Cumulative Fatigue Damage 

34 Fatigue is a time-limited aging analysis (TLAA) as defined in Title 10 of the Code of Federal 

35 Regulations (10 CFR) 54.3. TLAAs are required to be evaluated in accordance with 

36 10 CFR 54.21(c). This TLAA is addressed separately in Section 4.3, “Metal Fatigue Analysis,” 

37 of this SRP-SLR. The related GALL-SLR Report items invoked by Table 3.4-1 item 1 are 

38 VIII.D1.S-11, VIII.D2.S-11, VIII.G.S-11, VIII.B1.S-08, VIII.B2.S-08. 
3.4-3 

1 3.4.2.2.2 Cracking Due to Stress Corrosion Cracking 

2 Cracking due to SCC could occur for SS piping, piping components, and tanks exposed to 

3 outdoor air or any air environment when the component is insulated. The possibility of cracking 

4 also extends to indoor components located in close proximity to sources of outdoor air 

5 (e.g., components near intake vents). Cracking is known to occur in environments containing 

6 sufficient halides (e.g., chlorides) and in which moisture is possible. 

7 Applicable outdoor air environments (and associated local indoor air environments) include, but 

8 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

9 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

10 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

11 compounds, and areas subject to chloride contamination from other agricultural or 

12 industrial sources. 

13 Insulated SS components exposed to indoor air environments and outdoor air environments are 

14 susceptible to SCC if the insulation contains certain contaminants. Leakage of fluids through 

15 bolted connections (e.g., flanges, valve packing) can result in contaminants present in the 

16 insulation leaching onto the component surface. For outdoor insulated SS components, rain 

17 and changing weather conditions can result in moisture intrusion of the insulation. 

18 The applicant may demonstrate that SCC is not expected to occur by one or more of the 

19 following applicable means. 

20  For outdoor uninsulated components, describing the outdoor air environment present at 

21 the plant and demonstrating that SCC is not expected. 

22  For underground components, the applicant may demonstrate that SCC due to exposure 

23 to in-leakage to the vault as a result of external precipitation or groundwater is not 

24 expected. 

25  For insulated components, determining that the insulation does not contain sufficient 

26 contaminants to cause SCC. One acceptable means to demonstrate this is provided by 

27 Regulatory Guide 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

28  For indoor components, determining that there are no liquid-filled systems with threaded 

29 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

30  For all components, demonstrating that the aggressive environment is not present by 

31 isolating the component from the environment using a barrier to prevent loss of material 

32 due to pitting or crevice corrosion. An acceptable barrier includes tightly-adhering 

33 coatings that have been demonstrated to be impermeable to aqueous solutions and 

34 atmospheric air that contain halides. If a barrier coating is credited for isolating a 

35 component from a potentially aggressive environment then the barrier coating is 

36 evaluated to verify that it is impervious to the plant-specific environment. GALL-SLR 

37 Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

38 Heat Exchangers, and Tanks,” is an acceptable method to manage the integrity of a 

39 barrier coating for internal or external coatings. 

40 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

41 to manage this aging effect based on the environmental conditions applicable to the plant and 

42 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

43 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 
3.4-4 

1 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

2 manage cracking of SS due to SCC in piping, piping components, and tanks. 

3 3.4.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion 

4 Loss of material due to pitting and crevice corrosion could occur in SS piping, piping 

5 components, and tanks exposed to outdoor air or any air environment when the component is 

6 insulated or where the component is in the vicinity of insulated components. The possibility of 

7 pitting and crevice corrosion also extends to indoor components located in close proximity to 

8 sources of outdoor air (e.g., components near intake vents). Pitting and crevice corrosion is 

9 known to occur in environments containing sufficient halides (e.g., chlorides) and in which the 

10 presence of moisture is possible. 

11 Applicable outdoor air environments (and associated local indoor air environments) include, but 

12 are not limited to, those within approximately 5 miles of a saltwater coastline, within 1/2 mile of a 

13 road which is treated with salt in the wintertime, areas in which the soil contains more than trace 

14 chlorides, plants having cooling towers where the water is treated with chlorine or chlorine 

15 compounds, and areas subject to chloride contamination from other agricultural or 

16 industrial sources. 

17 Insulated SS components exposed to indoor air environments and outdoor air environments are 

18 susceptible to loss of material due to pitting or crevice corrosion if the insulation contains certain 

19 contaminants. Leakage of fluids through mechanical connections such as bolted flanges and 

20 valve packing can result in contaminants leaching onto the component surface. For outdoor 

21 insulated SS components, rain and changing weather conditions can result in moisture intrusion 

22 of the insulation. 

23 The applicant may demonstrate that loss of material due to pitting and crevice corrosion is not 

24 expected to occur by one or more of the following applicable means. 

25  For outdoor uninsulated components, describing the outdoor air environment present at 

26 the plant and demonstrating that external pitting or crevice corrosion is not expected. 

27  For underground components, the applicant may demonstrate that loss of material due 

28 to pitting or crevice corrosion due to exposure to in-leakage to the vault as a result of 

29 external precipitation or groundwater is not expected. 

30  For insulated components, determining that the insulation does not contain sufficient 

31 contaminants to cause loss of material due to pitting or crevice corrosion. One 

32 acceptable means to demonstrate this is provided by Regulatory Guide 1.36, 

33 “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

34  For indoor components, determining that there are no liquid-filled systems with threaded 

35 or bolted connections (e.g., flanges, valve packing) that could leak onto the component. 

36  For all components, demonstrating that the aggressive environment is not present by 

37 isolating the component from the environment using a barrier to prevent loss of material 

38 due to pitting or crevice corrosion. An acceptable barrier includes coatings that have 

39 been demonstrated to be impermeable to aqueous solutions and atmospheric air that 

40 contain halides. If a barrier coating is credited for isolating a component from a 

41 potentially aggressive environment, then the barrier coating is evaluated to verify that it 

42 is impervious to the plant-specific environment. GALL-SLR Report AMP XI.M42, 

43 “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, 
3.4-5 

1 and Tanks,” is an acceptable method to manage the integrity of a barrier coating for 

2 internal or external coatings. 

3 The GALL-SLR Report recommends further evaluation to determine whether an AMP is needed 

4 to manage this aging effect based on the environmental conditions applicable to the plant and 

5 requirements applicable to the components. GALL-SLR AMP XI.M36, “External Surfaces 

6 Monitoring,” GALL-SLR AMP XI.M29, “Aboveground Metallic Tanks,” or AMP XI.M41, “Buried 

7 and Underground Piping and Tanks,” (for underground components) are acceptable methods to 

8 manage loss of material due to pitting and crevice corrosion in SS piping, piping components, 

9 and tanks. 

10 3.4.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

11 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

12 confirmation process, and administrative controls. Safety related components are covered by 

13 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

14 Appendix B does not apply to nonsafety-related components that are subject to an AMP for 

15 SLR. Nevertheless, the applicant has the option to expand the scope of its 

16 10 CFR Part 50, Appendix B program to include these components and address these program 

17 elements. If the applicant chooses this option, the reviewer verifies that the applicant has 

18 documented such a commitment in the FSAR Supplement. If the applicant chooses alternative 

19 means, the branch responsible for quality assurance (QA) should be requested to review the 

20 applicant’s proposal on a case-by-case basis. 

21 Acceptance criteria are described in Branch Technical Position (BTP) IQMB-1 (Appendix A.2, of 

22 this SRP-SLR Report). 

23 3.4.2.2.5 Ongoing Review of Operating Experience 

24 Acceptance criteria are described in Appendix A.4, “Operating Experience for Aging 

25 Management Programs.” 

26 3.4.2.2.6 Loss of Material Due to Recurring Internal Corrosion 

27 Recurring internal corrosion can result in the need to augment AMPs beyond the 

28 recommendations in the GALL-SLR Report. During the search of plant-specific operating 

29 experience conducted during the SLRA development, recurring internal corrosion can be 

30 identified by the number of occurrences of aging effects and the extent of degradation at each 

31 localized corrosion site. This further evaluation item is applicable if the search of plant-specific 

32 operating experience reveals repetitive occurrences (e.g., one per refueling outage cycle that 

33 has occurred: (a) in any three or more cycles for a 10-year operating experience search, or 

34 (b) in any two or more cycles for a 5-year operating experience search) of aging effects with the 

35 same aging mechanism in which the aging effect resulted in the component either not meeting 

36 plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 

37 50 percent (regardless of the minimum wall thickness). 

38 The GALL-SLR Report recommends that a plant-specific AMP, or a new or existing AMP, be 

39 evaluated for inclusion of augmented requirements to ensure the adequate management of any 

40 recurring aging effect(s). Potential augmented requirements include: (i) alternative examination 

41 methods (e.g., volumetric versus external visual); (ii) augmented inspections (e.g., a greater 

42 number of locations, additional locations based on risk insights based on susceptibility to aging 

43 effect and consequences of failure, a greater frequency of inspections), and (iii) additional 
3.4-6 

1 trending parameters and decision points where increased inspections would be implemented. 

2 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report).” 

3 The applicant states: (a) why the program’s examination methods will be sufficient to detect the 

4 recurring aging effect before affecting the ability of a component to perform its intended function, 

5 (b) the basis for the adequacy of augmented or lack of augmented inspections, (c) what 

6 parameters will be trended as well as the decision points where increased inspections would be 

7 implemented (e.g., the extent of degradation at individual corrosion sites, the rate of degradation 

8 change), (d) how inspections of components that are not easily accessed (i.e., buried, 

9 underground) will be conducted, and (e) how leaks in any involved buried or underground 

10 components will be identified. 

11 Plant-specific operating experience examples should be evaluated to determine if the chosen 

12 AMP should be augmented even if the thresholds for significance of aging effect or frequency of 

13 occurrence of aging effect have not been exceeded. For example, during a 10-year search of 

14 plant specific operating experience, two instances of 360 degree 30 percent wall loss occurred 

15 at copper alloy to steel joints. Neither the significance of the aging effect nor the frequency of 

16 occurrence of aging effect threshold has been exceeded. Nevertheless, the operating 

17 experience should be evaluated to determine if the AMP that is proposed to manage the aging 

18 effect is sufficient (e.g., method of inspection, frequency of inspection, number of inspections) to 

19 provide reasonable assurance that the current licensing basis (CLB) intended functions of the 

20 component will be met throughout the subsequent period of extended operation. Likewise, the 

21 GALL-SLR Report AMR items associated with the new further evaluation items only cite raw 

22 water and waste water environments because operating experience indicates that these are the 

23 predominant environments associated with recurring internal corrosion; however, if the search 

24 of plant-specific operating experience reveals recurring internal corrosion in other water 

25 environments (e.g., treated water), the aging effect should be addressed in a similar manner. 

26 3.4.2.2.7 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

27 SCC is a form of environmentally assisted cracking which is known to occur in high and 

28 moderate strength aluminum alloys. The three conditions necessary for SCC to occur in a 

29 component are a sustained tensile stress, aggressive environment, and material with a 

30 susceptible microstructure. The aging effect of cracking due to SCC can be mitigated by 

31 eliminating one of the three necessary conditions. For the purposes of SLR, acceptance criteria 

32 for this further evaluation is being provided for demonstrating that the specific material is not 

33 susceptible to SCC or an aggressive environment is not present. The susceptibility of the 

34 material is to be established prior to evaluating the environment. This further evaluation item is 

35 applicable unless it is demonstrated by the applicant that one of the two necessary conditions 

36 discussed below is absent. 

37 Susceptible Material: If the material that a component is constructed of is not susceptible to 

38 SCC then the aging effect is not applicable. The microstructure of an aluminum alloy, of which 

39 alloy composition is only one factor, is what determines if the alloy is susceptible to SCC. 

40 Therefore, providing guidance based on alloy composition will not always successfully protect 

41 against SCC in aluminum alloys. The temper, condition, and product form of the alloy is 

42 considered when assessing if a material is susceptible to SCC. Aluminum alloys that are 

43 susceptible to SCC include: 

44  2xxx series alloys in the F, W, Ox, T3x, T4x, or T6x temper 

45  5xxx series alloys with a magnesium content of 3.5 weight percent or greater 
3.4-7 

1  6xxx series alloys in the F temper 

2  7xxx series alloys in the F, T5x, or T6x temper 

3  2xx.x and 7xx.x series alloys 

4  3xx.x series alloys that contain copper 

5  5xx.x series alloys with a magnesium content of greater than 8 weight percent 

6 The material is evaluated to verify that it is not susceptible to SCC and that the basis used to 

7 make the determination is technically substantiated. Tempers have been specifically developed 

8 to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper 

9 combination which are not susceptible to SCC when used in piping, piping component, and tank 

10 applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. 

11 GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” is an acceptable method to 

12 manage cracking of aluminum due to SCC in tanks. GALL-SLR Report AMP XI.M36, “External 

13 Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage cracking 

14 of aluminum due to SCC in piping and piping components. GALL-SLR Report AMP XI.M41, 

15 “Buried and Underground Piping and Tanks,” is an acceptable method to manage cracking of 

16 aluminum due to SCC in piping and tanks which are buried or underground. GALL-SLR Report 

17 AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

18 Components” is an acceptable method to manage cracking of aluminum due to SCC in 

19 components that are not included in other AMPs. Additional acceptance criteria are described 

20 in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

21 Aggressive Environment: If the environment that an aluminum alloy is exposed to is not 

22 aggressive, such as dry gas, controlled indoor air, or treated water, then cracking due to SCC 

23 will not occur and the aging effect is not applicable. Aggressive environments that are known to 

24 result in cracking of susceptible aluminum alloys due to SCC are aqueous solutions and 

25 atmospheric air that contain halides (e.g., chloride). Halide concentrations should generally be 

26 considered high enough to facilitate SCC of aluminum alloys in uncontrolled or untreated 

27 aqueous solutions and atmospheric air, such as outdoor air, raw water, waste water, and 

28 condensation, unless demonstrated otherwise. If an aluminum component is encapsulated in a 

29 secondary material, such as insulation or concrete, the composition of the encapsulating 

30 material is evaluated for halides. The environment that the aluminum alloy is exposed to is 

31 evaluated to verify that it is either controlled or treated and free of halides. 

32 An alternative strategy to demonstrating that an aggressive environment is not present is to 

33 isolate the aluminum alloy from the environment using a barrier to prevent SCC. Acceptable 

34 barriers include tightly adhering coatings that have been demonstrated to be impermeable to 

35 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

36 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

37 evaluated to verify that it is imperially to the plant-specific environment. GALL-SLR Report 

38 AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

39 Exchangers, and Tanks,” or equivalent program is an acceptable method to manage the 

40 integrity of a barrier coating. 

41 3.4.2.2.8 Loss of Material Due to General, Crevice or Pitting Corrosion and 

42 Microbiologically-Induced Corrosion and Cracking Due to Stress 

43 Corrosion Cracking 

44 Loss of material due to general (steel only), crevice, or pitting corrosion and microbiologically45 induced corrosion and cracking due to SCC (SS only) can occur in steel and SS piping and 
3.4-8 

1 piping components exposed to concrete. Concrete provides a high alkalinity environment that 

2 can mitigate the effects of loss of material for steel piping, thereby significantly reducing the 

3 corrosion rate. However, if water intrudes through the concrete, the pH can be reduced and 

4 ions that promote loss of material such as chlorides, which can penetrate the protective oxide 

5 layer created in the high alkalinity environment, can reach the surface of the metal. Carbonation 

6 can reduce the pH within concrete. The rate of carbonation is reduced by using concrete with a 

7 low water-to-cement ratio and low permeability. Concrete with low permeability also reduces 

8 the potential for the penetration of water. Adequate air entrainment improves the ability of the 

9 concrete to resist freezing and thawing cycles and therefore reduces the potential for cracking 

10 and intrusion of water. Intrusion of water can also bring bacteria to the surface of the metal, 

11 potentially resulting in microbiologically-induced corrosion in steel or SS. Cracking due to SCC, 

12 as well as pitting and crevice corrosion can occur due to halides present in the water that 

13 penetrates to the surface of the metal. 

14 If the following conditions are met, loss of material is not considered to be an applicable aging 

15 effect for steel: (a) attributes of the concrete are consistent with American Concrete Institute 

16 (ACI) 318 or ACI 349 (low water-to-cement ratio, low permeability, and adequate air 

17 entrainment) as cited in NUREG–1557; (b) plant-specific operating experience indicates no 

18 degradation of the concrete that could lead to penetration of water to the metal surface; and 

19 (c) the piping is not potentially exposed to groundwater. For SS components loss of material 

20 and cracking due to SCC are not considered to be applicable aging effects as long as the piping 

21 is not potentially exposed to groundwater. Where these conditions are not met, loss of material 

22 due to general (steel only), crevice, or pitting corrosion, and microbiologically-induced corrosion 

23 and cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

24 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

25 these aging effects. 

26 3.4.2.2.9 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically27 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

28 Water, or Sodium Pentaborate Solution 

29 Loss of material due to crevice corrosion can occur in steel with SS cladding, SS, and nickel 

30 alloy piping, piping components, heat exchanger components, spent fuel storage racks, tanks, 

31 and PWR heat exchanger components exposed to treated water, treated borated water, or 

32 sodium pentaborate solution if oxygen levels are greater than 100 parts per billion (ppb). In 

33 addition, loss of material due to pitting can occur if oxygen levels are greater than 100 ppb, 

34 halides or sulfates levels are greater than 150 ppb, and stagnant flow conditions exist. Loss of 

35 material due to microbiologically-induced corrosion can occur with steel with SS cladding, SS, 

36 and nickel alloy piping, piping components, heat exchanger components, spent fuel storage 

37 racks, tanks, and PWR heat exchanger components exposed to treated water, treated borated 

38 water, or sodium pentaborate solution if the pH is less than 10.5 and temperature is less than 

39 99 °C [210 °F]. 

40 Where oxygen levels are less than or equal to 100 ppb, GALL-SLR Report AMP XI.M2, “Water 

41 Chemistry,” and GALL-SLR Report AMP XI.M32, “One-Time Inspection,” are acceptable 

42 methods to manage loss of material due to pitting and crevice corrosion. Where oxygen levels 

43 are greater than 100 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR 

44 Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

45 Components,” are acceptable methods to manage loss of material due to crevice corrosion. 

46 Where stagnant flow conditions exist, and oxygen levels are greater than 100 ppb and halides 

47 or sulfates levels are greater than 150 ppb, GALL-SLR Report AMP XI.M2, “Water Chemistry,” 
3.4-9 

1 and GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

2 and Ducting Components,” are acceptable methods to manage loss of material due to pitting 

3 and crevice corrosion. 

4 Where the pH is greater than or equal to 10.5 and the temperature is greater than or equal to 

5 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and GALL-SLR Report 

6 AMP XI.M32, “One-Time Inspection,” are acceptable methods to manage loss of material due to 

7 loss of material due to microbiologically-induced corrosion. Where the pH is less than 10.5 and 

8 temperature is less than 99 °C [210 °F], GALL-SLR Report AMP XI.M2, “Water Chemistry,” and 

9 GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

10 Ducting Components,” are acceptable methods to manage loss of material due to 

11 microbiologically-induced corrosion. 

12 3.4.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

13 Loss of material due to pitting and crevice corrosion could occur in aluminum piping, piping 

14 components, and tanks exposed to an air environment for a sufficient duration of time. Air 

15 environments known to result in pitting and/or crevice corrosion of aluminum alloys are those 

16 that contain halides (e.g., chloride) and periodic moisture. The moisture level and halide 

17 concentration in atmospheric and uncontrolled air are greatly dependent on geographical 

18 location and site-specific conditions. Moisture level and halide concentration should generally 

19 be considered high enough to facilitate pitting and/or crevice corrosion of aluminum alloys in 

20 atmospheric and uncontrolled air, unless demonstrated otherwise. The periodic introduction of 

21 moisture or halides into an air environment from secondary sources should also be considered. 

22 Leakage of fluids from mechanical connections, such as bolted flanges and valve packing, 

23 through insulation onto a component in indoor controlled air is an example of a secondary 

24 source that should be considered. The operating experience (OE) and condition of aluminum 

25 alloy components are evaluated to determine if the plant-specific air environment is aggressive 

26 enough to result in pitting and crevice corrosion after prolonged exposure. The aging effect of 

27 loss of material due to pitting and crevice corrosion in aluminum alloys is not applicable and 

28 does not require management if: (a) the plant-specific OE does not reveal a history of pitting or 

29 crevice corrosion and (b) a one-time inspection demonstrates that the aging effect is not 

30 occurring or that loss of material due to pitting or crevice corrosion is occurring so slowly that it 

31 will not affect the intended function of the components. 

32 The internal surfaces of aluminum components do not need to be inspected if: (a) the review of 

33 OE does not reveal a history of pitting or crevice corrosion; and (b) inspection results for 

34 external surfaces demonstrate that the aging effect is not applicable. Inspection results 

35 associated with the periodic introduction of moisture or halides from secondary sources may be 

36 treated as a separate population of components. In the environment of air-indoor controlled, 

37 pitting and crevice corrosion is only expected to occur as the result of secondary source of 

38 moisture or halides. Alloy susceptibility may be considered when reviewing OE and interpreting 

39 inspection results. Inspections focus on the most susceptible alloys and locations. 

40 The GALL-SLR Report recommends the further evaluation of aluminum piping, piping 

41 components, and tanks exposed to an air environment to determine whether an AMP is needed 

42 to manage the aging effect of loss of material due to pitting and crevice corrosion. GALL-SLR 

43 Report AMP XI.M32, “One-Time Inspection,” is an acceptable method to demonstrate that the 

44 aging effect of loss of material due to pitting and crevice corrosion is not occurring at a rate that 

45 affects the intended function of the components. If loss of material due to pitting or crevice 

46 corrosion has occurred and is sufficient to potentially affect the intended function of an 
3.4-10 

1 aluminum SSC, the following AMPs are acceptable methods to manage loss of material due to 

2 pitting or crevice corrosion: (i) GALL-SLR Report AMP XI.M29, “Aboveground Metallic Tanks,” 

3 for tanks; (ii) GALL-SLR Report AMP XI.M36, "External Surfaces Monitoring of Mechanical 

4 Components,” for external surfaces of piping and piping components; (iii) GALL-SLR Report 

5 AMP XI.M41, “Buried and Underground Piping and Tanks,” for underground piping, piping 

6 components and tanks; and (iv) GALL-SLR Report Chapter XI.M38, "Inspection of Internal 

7 Surfaces in Miscellaneous Piping and Ducting Components” for internal surfaces of components 

8 that are not included in other aging management programs. 

9 3.4.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

10 Generic Aging Lessons Learned for Subsequent License Renewal Report 

11 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

12 3.4.2.4 Aging Management Programs 

13 For those AMPs that will be used for aging management and are based on the program 

14 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

15 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

16 GALL-SLR Report, Chapters X and XI. 

17 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

18 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

19 10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

20 AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

21 SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

22 Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, 

23 the difference should be reviewed and properly dispositioned. The reviewer should document 

24 the disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

25 The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP 

26 to be declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is 

27 compared. The reviewer is to confirm both that the enhancement, when implemented, would 

28 allow the existing SLRA AMP to be consistent with the GALL-SLR Report AMP and also that the 

29 applicant has a commitment in the FSAR Supplement to implement the enhancement prior to 

30 the subsequent period of extended operation. The reviewer should document the disposition of 

31 all enhancements. 

32 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

33 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

34 (Appendix A.1.2.3 of this SRP-SLR Report). 

35 3.4.2.5 Final Safety Analysis Report Supplement 

36 The summary description of the programs and activities for managing the effects of aging for the 

37 subsequent period of extended operation in the FSAR Supplement should be sufficiently 

38 comprehensive that later changes can be controlled by 10 CFR 50.59. The description should 

39 contain information associated with the bases for determining that aging effects will be managed 

40 during the subsequent period of extended operation. The description should also contain any 

41 future aging management activities, including enhancements and commitments, to be 

42 completed before the subsequent period of extended operation. Table 3.0-1 of this SRP-SLR 
3.4-11 

1 provides examples of the type of information to be included in the FSAR Supplement. 

2 Table 3.4-2 lists the programs that are applicable for this SRP-SLR subsection. 

3 3.4.3 Review Procedures 

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

5 3.4.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

6 Learned for Subsequent License Renewal Report 

7 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

8 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

9 approved in the GALL-SLR Report. The reviewer should not conduct a re-review of the 

10 substance of the matters described in the GALL-SLR Report. If the applicant has provided the 

11 information necessary to adopt the finding of program acceptability as described and evaluated 

12 in the GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to the 

13 GALL-SLR Report in its SLRA. In making this determination, the reviewer confirms that the 

14 applicant has provided a brief description of the system, components, materials, and 

15 environment. The reviewer also confirms that the applicable aging effects have been addressed 

16 based on the NRC staff’s review of industry and plant-specific operating experience. 

17 Furthermore, the reviewer should confirm that the applicant has addressed operating 

18 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

19 requires the reviewer to confirm that the applicant has identified those aging effects for the 

20 steam and power conversion system components that are contained in the GALL-SLR Report 

21 as applicable to its plant. 

22 3.4.3.2 Aging Management Review Results for Which Further Evaluation Is 

23 Recommended by the Generic Aging Lessons Learned for Subsequent License 

24 Renewal Report 

25 The basic review procedures defined in Subsection 3.4.3.1 need to be applied first for all of the 

26 AMRs and AMPs provided in this section. In addition, if the GALL-SLR Report AMR item to 

27 which the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

28 additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

29 effect/aging mechanism combinations. Refer to Table 3.4-1 for the item references for the 

30 following subsections. 

31 3.4.3.2.1 Cumulative Fatigue Damage 

32 Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

33 accordance with 10 CFR 54.21(c). The reviewer reviews the evaluation of this TLAA separately 

34 following the guidance in Section 4.3 of this SRP-SLR. 

35 3.4.3.2.2 Cracking Due to Stress Corrosion Cracking 

36 The GALL-SLR Report recommends further evaluation to manage cracking due to SCC of SS 

37 and aluminum piping, piping components, and tanks exposed to outdoor air environments 

38 containing sufficient halides (e.g., chlorides) and in which condensation is possible. The 

39 possibility of cracking also extends to components exposed to air which has recently been 

40 introduced into buildings (i.e., components near intake vents.) 
3.4-12 

1 If the applicant claims that neither the environment nor composition of insulation will result in 

2 stress corrosion cracking, the reviewer should evaluate the applicant’s data to verify that 

3 sufficient halides will not be present on the surface of the SS piping, piping components, or 

4 tanks. If the applicant elects to manage stress corrosion cracking, the reviewer should 

5 determine whether an adequate program is credited to manage the aging effect based on the 

6 applicable environmental conditions. 

7 3.4.3.2.3 Loss of Material Due to Pitting and Crevice Corrosion 

8 The GALL-SLR Report recommends further evaluation to manage loss of material due to pitting 

9 and crevice corrosion of SS piping, piping components, and tanks exposed to outdoor air or any 

10 air environment when the component is insulated where the presence of sufficient halides 

11 (e.g., chlorides) and moisture is possible. The possibility of pitting and crevice corrosion 

12 also extends to indoor components located in close proximity to sources of outdoor air 

13 (e.g., components near intake vents). 

14 If the applicant claims that neither the environment nor composition of the insulation will result in 

15 loss of material due to pitting and crevice corrosion, the reviewer should evaluate the applicant’s 

16 data to verify that sufficient halides will not be present on the surface of the SS piping, piping 

17 components, or tanks. If the applicant elects to manage loss of material due to pitting or crevice 

18 corrosion, the reviewer should determine whether an adequate program is credited to manage 

19 the aging effect based on the applicable environmental conditions. 

20 3.4.3.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

21 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

22 confirmation process, and administrative controls. Safety-related components are covered by 

23 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

24 Appendix B does not apply to nonsafety-related components that are subject to an AMP for 

25 SLR. Nevertheless, the applicant has the option to expand the scope of its 10 CFR Part 50, 

26 Appendix B program to include these components and address these program elements. If the 

27 applicant chooses this option, the reviewer confirms that the applicant has documented such a 

28 commitment in the FSAR Supplement. An example description is under “Quality Assurance” in 

29 Table 3.0-1, “FSAR Supplement for Aging Management of Applicable Systems.” If the applicant 

30 chooses alternative means, the branch responsible for QA should be requested to review the 

31 applicant’s proposal on a case-by-case basis. 

32 3.4.3.2.5 Ongoing Review of Operating Experience 

33 The applicant’s AMPs should contain the element of operating experience. The reviewer 

34 verifies that the applicant has appropriate programs or processes for the ongoing review of both 

35 plant-specific and industry operating experience concerning age-related degradation and aging 

36 management. Such reviews are used to ensure that the AMPs are effective to manage the 

37 aging effects for which they are created. The AMPs are either enhanced or new AMPs are 

38 developed, as appropriate, when it is determined through the evaluation of operating experience 

39 that the effects of aging may not be adequately managed. Additional information is in 

40 Appendix A.4, “Operating Experience for Aging Management Programs.” 

41 In addition, the reviewer confirms that the applicant has provided an appropriate summary 

42 description of these activities in the FSAR supplement. The GALL-SLR Report provides 

43 examples of the type of information to be included in the FSAR Supplement 
3.4-13 

1 3.4.3.2.6 Loss of Material Due to Recurring Internal Corrosion 

2 The GALL-SLR Report recommends further evaluation to manage recurring internal corrosion 

3 aging effects. The reviewer conducts an independent review of plant-specific operating 

4 experience to determine whether the plant is currently experiencing recurring internal corrosion. 

5 The scope of this further evaluation AMR item includes recurring aging effects in which the 

6 plant-specific operating experience review reveals repetitive occurrences (e.g., one per refueling 

7 outage that has occurred: (a) in any three or more cycles for a 10-year operating experience 

8 search, or (b) in any two or more cycles for a 5-year operating experience search) of aging 

9 effects with the same aging mechanism as a result of which the component either did not meet 

10 plant-specific acceptance criteria or experienced a reduction in wall thickness greater than 

11 50 percent (regardless of the minimum wall thickness). 

12 The reviewer should evaluate plant-specific operating experience examples to determine if the 

13 chosen AMP should be augmented. For example, during a 10-year search of plant specific 

14 operating experience, two instances of 360 degree 30 percent wall loss occurred at copper alloy 

15 to steel joints. Neither the significance of the aging effect nor the frequency of occurrence of 

16 aging effect threshold has been exceeded. Nevertheless, the operating experience should be 

17 evaluated to determine if the AMP that is proposed to manage the aging effect is sufficient 

18 (e.g., method of inspection, frequency of inspection, number of inspections) to provide 

19 reasonable assurance that the CLB intended functions of the component will be met throughout 

20 the subsequent period of extended operation. Likewise, the GALL-SLR Report AMR items 

21 associated with the new further evaluation items only cite raw water and waste water 

22 environments because operating experience indicates that these are the predominant 

23 environments associated with recurring internal corrosion; however, if the search of 

24 plant-specific operating experience reveals recurring internal corrosion in other water 

25 environments (e.g., treated water), the aging effect should be addressed in a similar manner. 

26 3.4.3.2.7 Cracking Due to Stress Corrosion Cracking in Aluminum Alloys 

27 The GALL-SLR Report recommends the further evaluation of aluminum components 

28 (i.e., piping, piping components, and tanks) exposed to atmospheric air or aqueous solutions 

29 that contain halides to manage cracking due to SCC. The reviewer must first determine if the 

30 aging effect of cracking due to SCC is applicable and requires aging management. The aging 

31 effect of cracking is to be considered applicable unless it is demonstrated that one of the two 

32 acceptance criteria are met by demonstrating that an aggressive environment is not present or 

33 the specific material is not susceptible, as discussed in Section 3.4.2.2.7. Additionally, guidance 

34 is also provided on the review of the third condition necessary for SCC to occur, a sustained 

35 tensile stress. Each of three conditions is evaluated based on the review procedures below. 

36 Susceptible Material: If the material used to fabricate the component being evaluated is not 

37 susceptible to SCC then the aging effect of cracking due to SCC is not applicable and does not 

38 require aging management. When determining if an aluminum alloy is susceptible to SCC the 

39 reviewer is to verify the material’s (a) alloy composition, (b) condition or temper, and (c) product 

40 form. Additionally, if the material was produced using a process specifically developed to 

41 provide a SCC resistant microstructure then the reviewer will consider the effects of this 

42 processing in the review. Once the material information has been established the reviewer is to 

43 evaluate the technical justification used to substantiate that the material is not susceptible to 

44 SCC when exposed to an aggressive environment and sustained tensile stress. The reviewer 

45 will evaluate all documentation and references used by the applicant as part of a 

46 technical justification. 
3.4-14 

1 Aggressive Environment: If the environment that an aluminum alloy is exposed to is not 

2 aggressive, such as dry gas, controlled indoor air, or treated water, then the aging effect of 

3 cracking due to SCC is not applicable and does not require aging management. The 

4 environments cited in the AMR line items in the GALL-SLR Report that reference this further 

5 evaluation are considered to be aggressive and potentially containing halide concentrations that 

6 facilitate SCC of aluminum alloys. The reviewer is to verify that components are not also 

7 periodically exposed to nontypical environments that would be categorized as aggressive, such 

8 as outdoor air which has recently been introduced into a building and the leakage/seepage of 

9 untreated aqueous solutions into a building or underground vault. Using information provided 

10 by the applicant, the reviewer will also evaluate the chemical composition of applicable 

11 encapsulating materials (e.g., concrete, insulation) for halides. 

12 If a barrier coating is employed to effectively isolate the aluminum alloy from an aggressive 

13 environment then the aging effect of cracking due to SCC is not applicable and does not require 

14 aging management. The reviewer is to verify that the barrier coating is impermeable to the 

15 plant-specific aqueous solutions and atmospheric air that the coating is intended to protect the 

16 alloy from being exposed to. If operating experience is cited as a technical justification for the 

17 effectiveness of a barrier coating the reviewer is to verify that the applicant has a program to 

18 manage loss of coating integrity equivalent to the GALL-SLR Report AMP XI.M42. 

19 Sustained Tensile Stress: If the sustained tensile stress being experienced by a component is 

20 below the SCC threshold value then cracking will not occur and the aging effect is not 

21 applicable. Many aluminum alloys do not have a true SCC threshold stress, although a practical 

22 SCC threshold value can be determined based on the material, service environment, and 

23 duration of intended function. The basis for the SCC threshold value is to be evaluated to 

24 determine its applicability. The magnitude of the maximum tensile service stress (applied and 

25 residual) experienced by the component is to be evaluated to verify that the stress levels are 

26 bounded by the SCC threshold value. 

27 The information necessary to eliminate the aging effect of SCC based on the sustained service 

28 stress is often not readily available. The SCC threshold stress level is dependent on both the 

29 alloy (e.g., chemical composition, processing history, and microstructure) and service 

30 environment. Furthermore, the magnitude and state of the residual stress sustained by a 

31 component is typically not fully characterized. The reviewer must determine the adequacy of 

32 both the SCC threshold value being used by the applicant and the magnitude of the tensile 

33 stress being experienced by the component. The evaluation of the SCC threshold value 

34 includes the verification that the (a) test method used to establish the threshold value is 

35 standardized and recognized by the industry, (b) data are statistically significant or conservative, 

36 and (c) data are for a relevant alloy, temper, product form, and environment. The evaluation of 

37 the tensile stress being experienced by the component includes the verification that the stress 

38 analysis accounts for (e) all applied and residual stresses and (f) stress raiser that can initiate 

39 SCC cracks, such as corrosion pits and fabrication defects. 

40 Documentation that may assist the reviewer in determining if the aging effect of cracking due to 

41 SCC is applicable and requires aging management include (a) component drawings, 

42 (b) applicable Codes or specifications used in the design, fabrication, and installation of the 

43 component, (c) material-specific material certification data and lot release data, and 

44 (d) maintenance records and plant-specific operating experience. 

45 If it is determined that the aging effect of cracking due to SCC is applicable the reviewer is to 

46 evaluate the applicants proposed AMP to ensure that the effects of aging on components are 
3.4-15 

1 adequately managed so that their intended functions will be maintained consistent with the CLB 

2 for the subsequent period of extended operation. The GALL-SLR Report AMP XI.M29, 

3 “Aboveground Metallic Tanks,” is an acceptable method to manage cracking of aluminum due to 

4 SCC in tanks. The GALL-SLR Report AMP XI.M36, “External Surfaces Monitoring of 

5 Mechanical Components,” is an acceptable method to manage cracking of aluminum due to 

6 SCC in piping, and piping components. The GALL-SLR Report AMP XI.M41, “Buried and 

7 Underground Piping and Tanks,” is an acceptable method to manage cracking of aluminum due 

8 to SCC in piping and tanks which are buried or underground. The GALL-SLR Report 

9 AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

10 Components” is an acceptable method to manage cracking of aluminum due to SCC in 

11 components that are not included in other AMPs. 

12 3.4.3.2.8 Loss of Material Due to General, Crevice or Pitting Corrosion and 

13 Microbiologically-Induced Corrosion and Cracking Due to Stress 

14 Corrosion Cracking 

15 The GALL-SLR Report recommends that for steel piping and piping components exposed to 

16 concrete, if the following conditions are met, loss of material is not considered to be an 

17 applicable aging effect for steel: (a) attributes of the concrete are consistent with ACI 318 or 

18 ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in 

19 NUREG–1557; (b) plant-specific operating experience indicates no degradation of the concrete 

20 that could lead to penetration of water to the metal surface; and (c) the piping is not potentially 

21 exposed to groundwater. For SS piping and piping components, loss of material and cracking 

22 due to SCC are not considered to be applicable aging effects as long as the piping is not 

23 potentially exposed to groundwater. Where these conditions are not met, loss of material due to 

24 general (steel only), crevice or pitting corrosion and microbiologically-induced corrosion and 

25 cracking due to SCC (SS only) are identified as applicable aging effects. GALL-SLR Report 

26 AMP XI.M41, “Buried and Underground Piping and Tanks,” is an acceptable method to manage 

27 these aging effects. 

28 The reviewer verifies that the concrete was specified to meet ACI 318 or ACI 349 (low water-to29 cement ratio, low permeability, and adequate air entrainment) as cited in NUREG–1557. The 

30 reviewer should evaluate plant-specific operating experience to determine whether concrete 

31 degradation sufficient to allow water intrusion has occurred. 

32 3.4.3.2.9 Loss of Material Due to Pitting and Crevice Corrosion and Microbiologically33 Induced Corrosion in Components Exposed to Treated Water, Treated Borated 

34 Water, or Sodium Pentaborate Solution 

35 The GALL-SLR Report recommends that loss of material due to crevice corrosion can occur in 

36 steel with SS cladding, SS, and nickel alloy piping, piping components, heat exchanger 

37 components, spent fuel storage racks, tanks, and PWR heat exchanger components exposed to 

38 treated water, treated borated water, or sodium pentaborate solution if oxygen levels are greater 

39 than 100 ppb. In addition, loss of material due to pitting can occur if oxygen levels are greater 

40 than 100 ppb, halides or sulfates levels are greater than 150 ppb, and stagnant flow conditions 

41 exist. Loss of material due to microbiologically-induced corrosion can occur with steel with SS 

42 cladding, SS, and nickel alloy piping, piping components, heat exchanger components, spent 

43 fuel storage racks, tanks, and PWR heat exchanger components exposed to treated water, 

44 treated borated water, or sodium pentaborate solution if the pH is less than 10.5 and 

45 temperature is less than 99 °C [210 °F]. 
3.4-16 

1 The reviewer verifies the applicant’s chemistry control parameters to determine whether 

2 GALL-SLR Report AMP XI.M2, “Water Chemistry,” and a one-time inspection program is 

3 implemented (e.g., GALL-SLR Report AMP XI.M32, “One-Time Inspection”) or GALL-SLR 

4 Report AMP XI.M2, “Water Chemistry,” and a periodic inspection program is implemented 

5 (e.g., GALL-SLR Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping 

6 and Ducting Components”) to manage loss of material. 

7 3.4.3.2.10 Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys 

8 The GALL-SLR Report recommends a further evaluation to determine whether an AMP is 

9 needed to manage the aging effect of loss of material due to pitting and crevice corrosion of 

10 aluminum piping, piping components, and tanks exposed to an air environment. If the applicant 

11 claims that a search of 10 years of plant-specific did not reveal any instances of loss of material 

12 due to pitting and crevice corrosion exposed to air environments, the staff conducts an 

13 independent review of plant-specific operating experience during the AMP audit. 

14 An alternative strategy to demonstrating that pitting and crevice corrosion is not applicable is to 

15 isolate the aluminum alloy from the air environment using a barrier. Acceptable barriers include 

16 anodization and tightly adhering coatings that have been demonstrated to be impermeable to 

17 aqueous solutions and atmospheric air that contain halides. If a barrier coating is credited for 

18 isolating an aluminum alloy from a potentially aggressive environment then the barrier coating is 

19 evaluated to verify that it is impermeable to the plant-specific environment. GALL-SLR Report 

20 AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

21 Exchangers, and Tanks,” is an acceptable method to manage the integrity of internal and 

22 external barrier coatings. 

23 The reviewer is to verify that the SLRA cites the use of GALL-SLR AMP XI.M32, "One-Time 

24 Inspection,” for all aluminum piping, piping components, and tanks exposed to air environments. 

25 Alternatively, if the applicant states that it will utilize a strategy of isolating the aluminum 

26 components from the environment, verify that the aluminum components are coated and 

27 GALL-SLR AMP XI.M42 has been cited to manage loss of coating integrity. 

28 3.4.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

29 Generic Aging Lessons Learned for Subsequent License Renewal Report 

30 The reviewer should confirm that the applicant, in its SLRA, has identified applicable aging 

31 effects, listed the appropriate combination of materials and environments, and has credited 

32 AMPs that will adequately manage the aging effects. The AMP credited by the applicant 

33 could be an AMP that is described and evaluated in the GALL-SLR Report or a 

34 plant-specific program. Review procedures are described in BTP RLSB-1 (Appendix A.1 of 

35 this SRP-SLR Report). 

36 3.4.3.4 Aging Management Programs 

37 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

38 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

39 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

40 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

41 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

42 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

43 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

44 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which 
3.4-17 

1 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

2 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

3 enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

4 pertinent to the steam and power conversion system are summarized in Table 3.4-1 of this 

5 SRP-SLR. The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR 

6 Report, Chapter VIII, presenting detailed information summarized by this row. 

7 Table 3.4-1 of this SRP-SLR may identify a plant-specific AMP. If the applicant chooses to use 

8 a plant-specific program that is not a GALL-SLR AMP, the NRC reviewer should confirm that 

9 the plant-specific program satisfies the criteria of BTP RLSB-1 (Appendix A.1.2.3 of this 

10 SRP-SLR Report). 

11 3.4.3.5 Final Safety Analysis Report Supplement 

12 The reviewer confirms that the applicant has provided in the FSAR supplement information 

13 equivalent to that in GALL-SLR for aging management of the steam and power conversion 

14 systems. Table 3.4-2 lists the AMPs that are applicable for this SRP-SLR subsection. The 

15 reviewer also confirms that the applicant has provided information for Subsection 3.4.3.3, 

16 “AMR Results Not Consistent with or Not Addressed in the GALL-SLR Report,” equivalent to 

17 that in Table 3.0-1. 

18 The NRC staff expects to impose a license condition on any renewed license to require the 

19 applicant to update its FSAR to include this FSAR Supplement at the next update required 

20 pursuant to 10 CFR 50.71(e)(4). As part of the license condition until the FSAR update is 

21 complete, the applicant may make changes to the programs described in its FSAR Supplement 

22 without prior NRC approval, provided that the applicant evaluates each such change and finds it 

23 acceptable pursuant to the criteria set forth in 10 CFR 50.59. If the applicant updates the 

24 FSAR to include the final FSAR supplement before the license is renewed, no condition will 

25 be necessary. 

26 As noted in Table 3.0-1, the applicant need not incorporate the implementation schedule into its 

27 FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

28 the SLRA to any future aging management activities, including enhancements and 

29 commitments, to be completed before entering the subsequent period of extended operation. 

30 The NRC staff expects to impose a license condition on any renewed license to ensure that the 

31 applicant will complete these activities no later than the committed date. 

32 3.4.4 Evaluation Findings 

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

34 provisions of this section, then an evaluation finding similar to the following text should be 

35 included in the NRC staff’s safety evaluation report: 

36 On the basis of its review, as discussed above, the NRC staff concludes that the 

37 applicant has demonstrated that the aging effects associated with the steam and 

38 power conversion system components will be adequately managed so that the 

39 intended functions will be maintained consistent with the CLB for the subsequent 

40 period of extended operation, as required by 10 CFR 54.21(a)(3). 

41 The NRC staff also reviewed the applicable FSAR Supplement program 

42 summaries and concludes that they adequately describe the AMPs credited for 
3.4-18 

1 managing aging of the steam and power conversion system, as required by 

2 10 CFR 54.21(d). 

3 3.4.5 Implementation 

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

5 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

7 3.4.6 References 

8 1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

9 for Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

10 March 2007. 

11 2. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

12 10 CFR Part 54 The License Renewal Rule.” Revision 6. Washington, DC: Nuclear 

13 Energy Institute. 1995. 
3.4-19 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 1 BWR/PWR Steel piping, piping 

components exposed to steam, treated water 

Cumulative fatigue damage due to fatigue 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.4.2.2.1) 

VIII.B1.S-08 VIII.B2.S-08 VIII.D1.S-11 VIII.D2.S-11 VIII.G.S-11 

M 2 BWR/PWR Stainless steel piping, 

piping components exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.A.SP-118 VIII.B1.SP-118 VIII.B2.SP-118 VIII.C.SP-118 VIII.D1.SP-118 VIII.D2.SP-118 VIII.E.SP-118 VIII.F.SP-118 VIII.G.SP-118 

M 3 BWR/PWR Stainless steel piping, 

piping components exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.A.SP-127 VIII.B1.SP-127 VIII.B2.SP-127 VIII.C.SP-127 VIII.D1.SP-127 VIII.D2.SP-127 VIII.E.SP-127 VIII.F.SP-127 VIII.G.SP-127 

 4 PWR Steel external 

surfaces, bolting exposed to air with borated water leakage 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No VIII.H.S-30 

VIII.H.S-40 

M 5 BWR/PWR Steel piping, piping 

components exposed to steam, treated water 

Wall thinning due to flow-accelerated corrosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No VIII.A.S-15 

VIII.B1.S-15 VIII.B2.S-15 VIII.C.S-15 VIII.D1.S-16 VIII.D2.S-16 
3.4-20 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

VIII.E.S-16 VIII.F.S-16 VIII.G.S-16 

M 6 BWR/PWR Steel, stainless steel 

bolting exposed to soil 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.SP-142 

VIII.H.SP-144 

 7 BWR/PWR High-strength steel 

closure bolting exposed to air with steam or water leakage 

Cracking due to cyclic loading, stress corrosion cracking 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-03 

 8 BWR/PWR Steel; stainless steel 

bolting, closure bolting exposed to air – outdoor (external), air – indoor uncontrolled (external) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.SP-82 

VIII.H.SP-84 

 9 BWR/PWR Steel closure bolting 

exposed to air with steam or water leakage 

Loss of material due to general corrosion 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-02 

M 10 BWR/PWR Copper alloy, nickel 

alloy, steel; stainless steel bolting, closure bolting exposed to any environment, air – outdoor (external), air – indoor uncontrolled (external) 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.SP-149 

VIII.H.SP-150 VIII.H.SP-151 VIII.H.SP-83 
3.4-21 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 11 BWR/PWR Stainless steel piping, 

piping components, tanks, heat exchanger components exposed to steam, treated water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-98 

VIII.B1.SP-88 VIII.B1.SP-98 VIII.B2.SP-98 VIII.C.SP-88 VIII.D1.SP-88 VIII.E.SP-88 VIII.E.SP-97 VIII.F.SP-85 VIII.F.SP-88 VIII.G.SP-88 

M 12 BWR/PWR Steel tanks exposed 

to treated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-75 

VIII.G.SP-75 

M 13 PWR Steel piping, piping 

components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.B1.SP-74 

VIII.D1.SP-74 VIII.F.SP-74 VIII.G.SP-74 

M 14 BWR/PWR Steel piping, piping 

components, PWR heat exchanger components exposed to steam, treated water 

Loss of material due to general, pitting, crevice corrosion, MIC (treated water only) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-71 

VIII.B1.SP-71 VIII.B2.SP-160 VIII.B2.SP-73 VIII.C.SP-71 VIII.C.SP-73 VIII.D2.SP-73 VIII.E.SP-73 VIII.E.SP-78 VIII.F.SP-78 

M 15 BWR/PWR Steel heat exchanger 

components exposed to treated water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-77 
3.4-22 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 16 BWR/PWR Copper alloy, 

aluminum piping, piping components exposed to treated water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC (copper alloy only) 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-101 

VIII.D1.SP-90 VIII.D2.SP-90 VIII.E.SP-90 VIII.F.SP-101 VIII.F.SP-90 VIII.G.SP-90 

 17 PWR Copper alloy heat 

exchanger tubes exposed to treated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.F.SP-100 

 18 BWR/PWR Copper alloy, 

stainless steel heat exchanger tubes exposed to treated water 

Reduction of heat transfer due to fouling 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.E.SP-100 

VIII.E.SP-96 VIII.F.SP-96 VIII.G.SP-100 

M 19 BWR/PWR Stainless steel, steel 

heat exchanger components exposed to raw water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC; fouling that leads to corrosion; flow blockage due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No VIII.E.SP-117 

VIII.E.SP-146 VIII.F.SP-146 VIII.F.SP-117 VIII.G.SP-117 VIII.G.SP-146 

M 20 BWR/PWR Copper alloy, 

stainless steel piping, piping components exposed to raw water 

Loss of material due to general (copper alloy only), pitting, crevice corrosion, MIC; flow blockage due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No VIII.A.SP-31 

VIII.E.SP-31 VIII.E.SP-36 VIII.F.SP-31 VIII.F.SP-36 
3.4-23 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

VIII.G.SP-31 VIII.G.SP-36 

D 21  22 BWR/PWR Stainless steel, 

copper alloy, steel heat exchanger tubes, heat exchanger components exposed to raw water 

Reduction of heat transfer due to fouling 

AMP XI.M20, "OpenCycle Cooling Water System" 

No VIII.E.S-28 

VIII.E.SP-56 VIII.F.S-28 VIII.F.SP-56 VIII.G.S-27 VIII.G.S-28 VIII.G.SP-56 

M 23 BWR/PWR Stainless steel piping, 

piping components exposed to closedcycle cooling water >60°C (>140°F) 

Cracking due to stress corrosion cracking 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.E.SP-54 

VIII.F.SP-54 VIII.G.SP-54 

D 24 M 25 BWR/PWR Steel heat exchanger 

components exposed to closed-cycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.A.S-23 

VIII.E.S-23 VIII.F.S-23 VIII.G.S-23 

M 26 BWR/PWR Stainless steel heat 

exchanger components, piping, piping components exposed to closedcycle cooling water 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.E.S-25 

VIII.E.SP-39 VIII.F.S-25 VIII.F.SP-39 VIII.G.S-25 VIII.G.SP-39 
3.4-24 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 27 BWR/PWR Copper alloy piping, 

piping components exposed to closedcycle cooling water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.E.SP-8 

VIII.F.SP-8 VIII.G.SP-8 

M 28 BWR/PWR Steel, stainless steel, 

copper alloy heat exchanger components and tubes exposed to closed-cycle cooling water 

Reduction of heat transfer due to fouling 

AMP XI.M21A, "Closed Treated Water Systems" 

No VIII.A.SP-64 

VIII.E.SP-41 VIII.E.SP-57 VIII.E.SP-64 VIII.F.SP-41 VIII.F.SP-64 VIII.G.SP-41 VIII.G.SP-64 

 29 BWR/PWR Steel tanks exposed 

to air – outdoor (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.S-31 

VIII.G.S-31 

M 30 BWR/PWR Steel tanks (within the 

scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete, air – outdoor, air – indoor uncontrolled, moist air, condensation (external) 

Loss of material due to general, pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.SP-115 

VIII.G.SP-116 

D 31 M 32 BWR/PWR Gray cast iron piping, 

piping components exposed to soil, ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.E.SP-26 

VIII.G.SP-26 
3.4-25 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 33 BWR/PWR Gray cast iron, copper 

alloy (>15% Zn or >8% Al) piping, piping components exposed to treated water, raw water, closed-cycle cooling water, soil, ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.A.SP-27 

VIII.A.SP-28 VIII.A.SP-30 VIII.E.S-440 VIII.E.SP-27 VIII.E.SP-29 VIII.E.SP-30 VIII.E.SP-55 VIII.F.S-440 VIII.F.SP-27 VIII.F.SP-29 VIII.F.SP-30 VIII.F.SP-55 VIII.G.S-440 VIII.G.SP-27 VIII.G.SP-28 VIII.G.SP-29 VIII.G.SP-30 VIII.G.SP-55 

M 34 BWR/PWR Steel external 

surfaces exposed to air – indoor uncontrolled (external), air – outdoor (external), condensation (external) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-29 

VIII.H.S-41 VIII.H.S-42 

M 35 BWR/PWR Aluminum piping, 

piping components exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.SP-147 
3.4-26 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 36 PWR Steel piping, piping 

components exposed to air – outdoor (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.B1.SP-59 

M 37 PWR Steel piping, piping 

components exposed to condensation (internal) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.B1.SP-60 

VIII.G.SP-60 

M 38 PWR Steel piping, piping 

components exposed to raw water 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.G.SP-136 

M 39 BWR/PWR Stainless steel piping, 

piping components exposed to condensation (internal) 

Loss of material due to pitting and crevice corrosion 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.B1.SP-110 

VIII.B2.SP-110 

M 40 BWR/PWR Steel piping, piping 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-91 

VIII.D1.SP-91 VIII.D2.SP-91 VIII.E.SP-91 VIII.G.SP-91 

 41 PWR Steel heat exchanger 

components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time 

No VIII.G.SP-76 
3.4-27 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

Inspection" 

M 42 PWR Aluminum piping, 

piping components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-114 

M 43 BWR/PWR Copper alloy piping, 

piping components exposed to lubricating oil 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-92 

VIII.D1.SP-92 VIII.D2.SP-92 VIII.E.SP-92 VIII.G.SP-92 

M 44 BWR/PWR Stainless steel piping, 

piping components, heat exchanger components exposed to lubricating oil 

Loss of material due to pitting, crevice corrosion, MIC 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-95 

VIII.D1.SP-95 VIII.D2.SP-95 VIII.E.SP-95 VIII.G.SP-79 VIII.G.SP-95 

 45 PWR Aluminum heat 

exchanger components and tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-113 

 46 PWR Stainless steel, steel, 

copper alloy heat exchanger tubes exposed to lubricating oil 

Reduction of heat transfer due to fouling 

AMP XI.M39, "Lubricating Oil Analysis," and AMP XI.M32, "One-Time Inspection" 

No VIII.G.SP-102 

VIII.G.SP-103 VIII.G.SP-99 
3.4-28 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 47 BWR/PWR Steel (with coating or 

wrapping), stainless steel, nickel-alloy piping, piping components, tanks exposed to soil, concrete 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.E.SP-145 

VIII.G.SP-145 

M 48 BWR/PWR Stainless steel, nickel 

alloy bolting exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-143 

M 49 BWR/PWR Stainless steel, nickel 

alloy piping, piping components exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.E.SP-94 

VIII.G.SP-94 

M 50 BWR/PWR Steel bolting exposed 

to soil, concrete 

Loss of material due to general, pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-141 

M 50x BWR/PWR Underground steel, 

nickel alloy,, copper alloy piping, piping components exposed to air-indoor uncontrolled, condensation, airoutdoor (external) 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.H.SP-161 

M 51 BWR/PWR Steel piping, piping 

components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.4.2.2.8) 

VIII.I.SP-154 
3.4-29 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

M 52 BWR/PWR Aluminum piping, 

piping components exposed to gas 

None None No VIII.I.SP-23 

M 53 PWR Copper alloy piping, 

piping components exposed to air with borated water leakage 

None None No VIII.I.SP-104 

M 54 BWR/PWR Copper alloy piping, 

piping components exposed to gas, air – indoor uncontrolled (external) 

None None No VIII.I.SP-5 

VIII.I.SP-6 

M 55 BWR/PWR Glass piping elements 

exposed to lubricating oil, air, air – outdoor, condensation, raw water, treated water, air with borated water leakage, gas, closedcycle cooling water, air – indoor uncontrolled (external) 

None None No VIII.I.SP-10 

VIII.I.SP-108 VIII.I.SP-33 VIII.I.SP-34 VIII.I.SP-35 VIII.I.SP-67 VIII.I.SP-68 VIII.I.SP-69 VIII.I.SP-70 VIII.I.SP-9 

M 56 BWR/PWR Nickel alloy piping, 

piping components exposed to air – indoor uncontrolled (external) 

None None No VIII.I.SP-11 

M 57 BWR/PWR Nickel alloy, PVC 

Piping, piping components exposed to air with borated water leakage, air – 

None None No VIII.I.SP-148 

VIII.I.SP-152 VIII.I.SP-153 
3.4-30 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

indoor uncontrolled, condensation (internal) 

M 58 BWR/PWR Stainless steel piping, 

piping components exposed to air – indoor uncontrolled (external), gas, air – indoor uncontrolled (internal) 

None None No VIII.I.SP-12 

VIII.I.SP-15 VIII.I.SP-86 

M 59 BWR/PWR Steel piping, piping 

components exposed to air – indoor controlled (external), gas 

None None No VIII.I.SP-1 

VIII.I.SP-4 

M 60 BWR/PWR Any material piping, 

piping components exposed to treated water 

Wall thinning due to erosion 

AMP XI.M17, "FlowAccelerated Corrosion" 

No VIII.D1.S-408 

VIII.D2.S-408 VIII.G.S-408 

M 61 BWR/PWR Metallic piping, piping 

components, tanks exposed to raw water, waste water 

Loss of material due to recurring internal corrosion 

Plant-specific aging management program

Yes (SRP-SLR Section 3.4.2.2.6) 

VIII.A.S-400 VIII.B1.S-400 VIII.B2.S-400 VIII.C.S-400 VIII.D1.S-400 VIII.D2.S-400 VIII.E.S-400 VIII.F.S-400 VIII.G.S-400 

M 62 BWR/PWR Steel, stainless steel 

or aluminum tanks (within the scope of AMP XI.M29, 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.S-405 

VIII.G.S-405 
3.4-31 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

"Aboveground Metallic Tanks") exposed to treated water 

M 63 BWR/PWR Insulated steel, 

copper alloy, copper alloy (> 15% Zn), aluminum piping, piping components, tanks exposed to condensation, air – outdoor 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion; cracking due to stress corrosion cracking (copper alloy (>15% Zn) only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-402 

M 64 BWR/PWR Jacketed thermal 

insulation in an air – indoor uncontrolled, air – outdoor environment, air with borated water leakage, air with reactor coolant leakage, or air with steam or water leakage 

Reduced thermal insulation resistance due to moisture intrusion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-403 

D 65 M 66 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to 

Loss of coating or lining integrity due to blistering, cracking, flaking, peeling, delamination, rusting, physical damage, 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.A.S-401 

VIII.B1.S-401 VIII.B2.S-401 VIII.C.S-401 VIII.D1.S-401 VIII.D2.S-401 
3.4-32 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

closed-cycle cooling water, raw water, treated water, treated borated water, lubricating oil 

spalling for cementitious coatings/linings 

VIII.E.S-401 VIII.F.S-401 VIII.G.S-401 

M 67 BWR/PWR Any material piping, 

piping components, heat exchangers, tanks with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, treated borated water, lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC; fouling that leads to corrosion; cracking due to stress corrosion cracking 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.A.S-414 

VIII.B1.S-414 VIII.B2.S-414 VIII.C.S-414 VIII.D1.S-414 VIII.D2.S-414 VIII.E.S-414 VIII.F.S-414 VIII.G.S-414 

M 68 BWR/PWR Gray cast iron piping 

components with internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, waste water 

Loss of material due to selective leaching 

AMP XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" 

No VIII.A.S-415 

VIII.B1.S-415 VIII.B2.S-415 VIII.C.S-415 VIII.D1.S-415 VIII.D2.S-415 VIII.E.S-415 VIII.F.S-415 VIII.G.S-415 

N 69 BWR/PWR Steel, stainless steel 

bolting exposed to condensation, lubricating oil 

Loss of preload due to thermal effects, gasket creep, or self-loosening 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-416 

VIII.H.S-417 

N 70 BWR/PWR Copper alloy bolting 

exposed to raw water, waste water 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-418 
3.4-33 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 71 BWR/PWR Steel bolting exposed 

to lubricating oil 

Loss of material due to general, pitting, crevice corrosion, MIC 

AMP XI.M18, "Bolting Integrity" 

No VIII.H.S-419 

N 72 BWR/PWR Stainless steel, 

aluminum piping, piping components exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.E.S-420 

VIII.G.S-420 

N 73 BWR/PWR Stainless steel bolting 

exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

No VIII.E.S-421 

VIII.G.S-421 

N 74 BWR/PWR Underground stainless 

steel piping, piping components, tanks exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.H.S-425 

N 75 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components exposed to air (external) 

Reduction of heat transfer due to fouling 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-426 

N 77 BWR/PWR Elastomer seals, 

piping, piping components exposed to air – outdoor 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-428 

N 78 BWR/PWR Elastomer seals, 

piping, piping components exposed to condensation 

Hardening and loss of strength due to elastomer degradation 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping 

No VIII.D1.S-429 

VIII.D2.S-429 VIII.E.S-429 VIII.G.S-429 
3.4-34 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

and Ducting Components" 

N 80 BWR/PWR Stainless steel, steel, 

nickel alloy, copper alloy, aluminum piping, piping components exposed to condensation 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-431 

N 81 BWR/PWR Steel components 

exposed to treated water, raw water 

Long-term loss of material due to general corrosion 

AMP XI.M32, "OneTime Inspection" No VIII.A.S-432 VIII.B1.S-432 

VIII.B2.S-432 VIII.C.S-432 VIII.D1.S-432 VIII.D2.S-432 VIII.E.S-432 VIII.F.S-432 VIII.G.S-432 

N 82 BWR/PWR Stainless steel piping, 

piping components exposed to concrete 

None None Yes (SRP-SLR 

Section 3.4.2.2.8) 

VIII.I.SP-13 

N 83 BWR/PWR Stainless steel tanks 

exposed to treated water 

Loss of material due to general (steel only), pitting, crevice corrosion, MIC 

Plant-specific aging management program

Yes (SRP-SLR Section 3.4.2.2.9) 

VIII.E.SP-162 VIII.G.SP-162 

N 84 BWR/PWR Stainless steel, nickel 

alloy piping, piping components exposed to steam 

Loss of material due to pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" 

No VIII.A.SP-155 

VIII.B1.SP-155 VIII.B2.SP-155 VIII.B1.SP-157 
3.4-35 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 85 BWR/PWR Stainless steel piping, 

piping components, PWR heat exchanger components exposed to treated water 

Loss of material due to pitting, crevice corrosion, MIC 

Plant-specific aging management program

Yes (SRP-LR Section 3.4.2.2.9) 

VIII.E.SP-80 VIII.E.SP-81 VIII.F.SP-81 VIII.B1.SP-87 VIII.C.SP-87 VIII.D1.SP-87 VIII.D2.SP-87 VIII.E.SP-87 VIII.F.SP-87 VIII.G.SP-87 

N 86 BWR/PWR Stainless steel, steel, 

aluminum, copper alloy, titanium heat exchanger components internal to components exposed to air (external) 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-433 

VIII.G.S-433 

N 88 PWR Copper alloy (≤8% Al) 

piping, piping components exposed to air with borated water leakage 

None None No VIII.I.S-435 

N 89 BWR/PWR Steel, stainless steel, 

copper alloy piping, piping components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.A.S-436 

VIII.E.S-436 VIII.F.S-436 VIII.G.S-436 
3.4-36 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 90 BWR/PWR Steel, stainless steel, 

copper alloy heat exchanger components exposed to raw water (for components not covered by NRC GL 89-13) 

Reduction of heat transfer due to fouling 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-437 

VIII.F.S-437 VIII.G.S-437 

N 91 BWR/PWR Steel, stainless steel, 

copper alloy heat exchanger components exposed to raw water (for components not covered by NRC GL 89-13) 

Loss of material due to general (steel and copper alloy only), pitting, crevice corrosion, MIC 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

No VIII.E.S-438 

VIII.F.S-438 VIII.G.S-438 

N 92 BWR/PWR Copper alloy (>15% 

Zn or >8% Al) piping, piping components exposed to soil ground water 

Loss of material due to selective leaching 

AMP XI.M33, "Selective Leaching" 

No VIII.D1.S-439 

VIII.D2.S-439 VIII.E.S-439 VIII.F.S-439 VIII.G.S-439 

N 93 BWR/PWR Stainless steel tanks 

exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.A.S-441 VIII.B1.S-441 VIII.B2.S-441 VIII.C.S-441 VIII.D1.S-441 VIII.D2.S-441 VIII.E.S-441 VIII.F.S-441 VIII.G.S-441 
3.4-37 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 94 BWR/PWR Underground 

aluminum piping, piping components exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program

Yes (SRP-SLR Section 3.4.2.2.10) 

VIII.H.S-442 

N 95 BWR/PWR Underground stainless 

steel piping, piping components exposed to air-indoor uncontrolled, condensation, airoutdoor (external) 

Loss of material due to pitting, crevice corrosion 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.H.S-443 

N 96 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.S-444 

VIII.G.S-444 

N 97 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air (external) 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program

Yes (SRP-SLR Section 3.4.2.2.10) 

VIII.E.S-445 VIII.G.S-445 

N 98 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air, air – outdoor, air – indoor uncontrolled, moist air, condensation 

Loss of material due to pitting, crevice corrosion 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.E.S-446 VIII.G.S-446 
3.4-38 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

(external) 

N 99 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Loss of material due to pitting, crevice corrosion, MIC (soil environment only) 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.S-447 

VIII.G.S-447 

N 100 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to air – outdoor, air – indoor uncontrolled, air – indoor controlled, condensation (external) 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.E.S-448 VIII.G.S-448 

N 101 BWR/PWR Stainless steel tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

No VIII.E.S-449 

VIII.G.S-449 

N 102 BWR/PWR Aluminum tanks 

(within the scope of AMP XI.M29, "Aboveground Metallic Tanks") exposed to soil, concrete, air – outdoor, air – indoor 

Cracking due to stress corrosion cracking 

AMP XI.M29, "Aboveground Metallic Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.E.S-450 VIII.G.S-450 
3.4-39 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

uncontrolled, air – indoor controlled, raw water, waste water, condensation 

N 103 BWR/PWR Insulated stainless 

steel piping, piping components, tanks exposed to condensation, air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.3) 

VIII.H.S-451 

N 104 BWR/PWR Insulated stainless 

steel tanks exposed to condensation, air – outdoor, air – indoor uncontrolled, air – indoor controlled 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.H.S-452 

N 105 BWR/PWR Insulated aluminum 

tanks exposed to condensation, air – outdoor, air – indoor uncontrolled, air – indoor controlled 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.H.S-453 

N 106 BWR/PWR Steel, stainless steel, 

copper alloy, copper alloy (> 15% Zn), nickel alloy piping, piping components exposed to air – outdoor 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion; cracking due to stress corrosion cracking (copper alloy (>15% Zn) only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-454 
3.4-40 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 107 BWR/PWR Steel, stainless steel, 

copper alloy, copper alloy (> 15% Zn), nickel alloy tanks exposed to condensation 

Loss of material due to general (steel, copper alloy only), pitting, crevice corrosion; cracking due to stress corrosion cracking (copper alloy (>15% Zn) only) 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

No VIII.H.S-455 

N 108 BWR/PWR Stainless steel piping, 

piping components, tanks exposed to condensation 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.2) 

VIII.H.S-456 

N 109 BWR/PWR Aluminum piping, 

piping components, tanks exposed to condensation, raw water, waste water 

Cracking due to stress corrosion cracking 

AMP XI.M36, "External Surfaces Monitoring of Mechanical Components" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.H.S-457 

N 110 BWR/PWR Aluminum piping, 

piping components exposed to air – outdoor, raw water, waste water, condensation (internal) 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.D1.S-458 VIII.D2.S-458 VIII.E.S-458 VIII.F.S-458 VIII.G.S-458 

N 111 BWR/PWR Aluminum tanks 

exposed to raw water, waste water, condensation (internal) 

Cracking due to stress corrosion cracking 

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.D1.S-459 VIII.D2.S-459 VIII.E.S-459 VIII.F.S-459 VIII.G.S-459 
3.4-41 

Table 3.4-1. Summary of Aging Management Programs for Steam and Power Conversion System Evaluated in Chapter VIII of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended GALL-SLR Item 

N 112 BWR/PWR Underground 

aluminum piping, piping components, tanks exposed to air – outdoor 

Cracking due to stress corrosion cracking 

AMP XI.M41, "Buried and Underground Piping and Tanks" 

Yes (SRP-SLR Section 3.4.2.2.7) 

VIII.H.S-460 

N 113 BWR/PWR Aluminum piping, 

piping components exposed to air – indoor uncontrolled 

Loss of material due to pitting, crevice corrosion 

Plant-specific aging management program

Yes (SRP-SLR Section 3.4.2.2.10) 

VIII.I.S-461 
3.4-42 

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

Management of Steam and Power Conversion System 

GALL-SLR Report 

Chapter/AMP 

Program Name 

AMP XI.M2 Water Chemistry 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M17 Flow-Accelerated Corrosion 

AMP XI.M18 Bolting Integrity 

AMP XI.M20 Open-Cycle Cooling Water System 

AMP XI.M21A Closed Treated Water Systems 

AMP XI.M29 Aboveground Metallic Tanks 

AMP XI.M32 One-Time Inspection 

AMP XI.M33 Selective Leaching 

AMP XI.M36 External Surfaces Monitoring of Mechanical Components 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components 

AMP XI.M39 Lubricating Oil Analysis 

AMP XI.M41 Buried and Underground Piping and Tanks 

AMP XI.M42 Internal Coatings/Linings for In Scope Piping, Piping Components, Heat 

Exchangers, and Tanks 

GALL-SLR Report 

Appendix A 

Quality Assurance for Aging Management Programs 

GALL-SLR Report 

Appendix B 

Operating Experience for Aging Management Programs 

SRP-SLR Appendix 

A.1 

Aging Management Review—Generic (Branch Technical Position 

RLSB-1) 
3.5-1 

1 3.5 Aging Management of Containments, Structures, and 

2 Component Supports 

3 Review Responsibilities 

4 Primary— Branch assigned responsibility by Project Manager (PM) as described in Section 3.0 

5 of this Standard Review Plan for Review of Subsequent License Renewal Applications for 

6 Nuclear Power Plants (SRP-SLR). 

7 3.5.1 Areas of Review 

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

9 management programs (AMPs) for containments, structures and components (SC) supports. 

10 For a recent vintage plant, the information related to containments, supports is contained in 

11 Chapter 3, “Design of Structures, Components, Equipment, and Systems,” of the plant’s final 

12 safety analysis report (FSAR), consistent with the “Standard Review Plan for the Review of 

13 Safety Analysis Reports for Nuclear Power Plants” (NUREG–0800). For older vintage plants, 

14 the location of applicable information is plant-specific because an older plant’s FSAR may have 

15 predated NUREG–0800. The scope of this section is containment structures, and safety-related 

16 and other SC supports. 

17 The pressurized water reactor (PWR) containment structures consist of concrete (reinforced or 

18 prestressed) and steel containments. The boiling water reactor (BWR) containment 

19 structures consist of Mark I, Mark II, and Mark III steel and concrete (reinforced or 

20 prestressed) containments. 

21 The safety-related structures (other than containments) are organized into nine groups: 

22 Group 1: BWR reactor building, PWR shield building, control room/building; Group 2: BWR 

23 reactor building with steel superstructure; Group 3: auxiliary building, diesel generator building, 

24 radwaste building, turbine building, switchgear room, yard structures [auxiliary feedwater (AFW) 

25 pump house, utility/piping tunnels, security lighting poles, manholes, duct banks], station 

26 blackout (SBO) structures (transmission towers, startup transformer circuit breaker foundation, 

27 electrical enclosure); Group 4: containment internal structures, excluding refueling canal; 

28 Group 5: fuel storage facility, refueling canal; Group 6: water-control structures (e.g., intake 

29 structure, cooling tower, and spray pond); Group 7: concrete tanks and missile barriers; 

30 Group 8: steel tank foundations and missile barriers; and Group 9: BWR unit vent stack. 

31 The component supports are organized into seven groups: Group B1.1: supports for American 

32 Society of Mechanical Engineers (ASME) Class 1 piping and components; Group B1.2: 

33 supports for ASME Class 2 and 3 piping and components; Group B1.3: supports for 

34 ASME Class MC components; Group B2: supports for cable tray, conduit, heating, ventilation, 

and air conditioning (HVAC) ducts, TubeTrack® 35 , instrument tubing, non-ASME piping and 

36 components; Group B3: anchorage of racks, panels, cabinets, and enclosures for electrical 

37 equipment and instrumentation; Group B4: supports for miscellaneous equipment 

38 [e.g., emergency diesel generator (EDG), HVAC components]; and Group B5: supports for 

39 miscellaneous structures (e.g., platforms, pipe whip restraints, jet impingement shields, 

40 masonry walls). 

41 The responsible review organization is to review the following subsequent license renewal 

42 application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 3.0, for review: 
3.5-2 

1 AMRs 

2  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

3 License Renewal (GALL-SLR) Report 

4  AMR results for which further evaluation is recommended 

5  AMR results that are not consistent with or not addressed in the GALL-SLR Report 

6 AMPs 

7  Consistent with GALL-SLR AMPs 

8  Plant-specific AMPs 

9 FSAR Supplement 

10  The responsible review organization is to review the FSAR Supplement associated with 

11 each assigned AMP. 

12 3.5.2 Acceptance Criteria 

13 The acceptance criteria for the areas of review describe methods for determining whether the 

14 applicant has met the requirements of the U.S. Nuclear Regulatory Commission (NRC) 

15 regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21. 

16 3.5.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

17 Learned for Subsequent License Renewal Report 

18 The AMRs and the AMPs applicable to structures and component supports are described and 

19 evaluated in Chapters II and III of the GALL-SLR Report. 

20 The applicant’s SLRA should provide sufficient information so that the reviewer is able to 

21 confirm that the specific SLRA AMR item and the associated SLRA AMP are consistent with the 

22 cited GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item 

23 is consistent with the GALL-SLR Report AMR item to which it is compared. 

24 When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, 

25 the reviewer should confirm that the alternate AMP is valid to use for aging management and 

26 will be capable of managing the effects of aging as adequately as the AMP recommended by 

27 the GALL-SLR Report. 

28 3.5.2.2 Aging Management Review Results for Which Further Evaluation Is 

29 Recommended by the Generic Aging Lessons Learned for Subsequent License 

30 Renewal Report 

31 The basic acceptance criteria defined in Section 3.5.2.1 need to be applied first for all of the 

32 AMRs and AMPs as part of this section. In addition, if the GALL-SLR Report AMR item to which 

33 the SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

34 additional criteria apply for each of the following aging effect/aging mechanism combinations. 

35 Refer to Table 3.5-1, comparing the “Further Evaluation Recommended” column and the 

36 “GALL-SLR Item” column, for the AMR items that reference the following subsections. 
3.5-3 

1 3.5.2.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 

2 3.5.2.2.1.1 Cracking and Distortion Due to Increased Stress Levels from Settlement; 

3 Reduction of Foundation Strength, and Cracking Due to Differential Settlement 

4 and Erosion of Porous Concrete Subfoundations 

5 Cracking and distortion due to increased stress levels from settlement could occur in PWR and 

6 BWR concrete and steel containments. The existing program relies on ASME Section XI, 

7 Subsection IWL to manage these aging effects. Also, reduction of foundation strength and 

8 cracking, due to differential settlement and erosion of porous concrete subfoundations could 

9 occur in all types of PWR and BWR containments. The existing program relies on the 

10 structures monitoring program to manage these aging effects. However, some plants may rely 

11 on a dewatering system to lower the site groundwater level. If the plant’s current licensing basis 

12 (CLB) credits a dewatering system to control settlement, further evaluation is recommended to 

13 verify the continued functionality of the dewatering system during the subsequent period of 

14 extended operation. 

15 3.5.2.2.1.2 Reduction of Strength and Modulus Due to Elevated Temperature 

16 Reduction of strength and modulus of concrete due to elevated temperatures could occur in 

17 PWR and BWR concrete and steel containments. The implementation of 10 CFR 50.55a and 

18 ASME Section XI, Subsection IWL would not be able to identify the reduction of strength and 

19 modulus of concrete due to elevated temperature. Subsection CC-3440 of ASME Section III, 

20 Division 2, specifies the concrete temperature limits for normal operation or any other long-term 

21 period. Further evaluation is recommended of a plant-specific AMP if any portion of the 

22 concrete containment components exceeds specified temperature limits {i.e., general area 

23 temperature greater than 66 °C [150 °F] and local area temperature greater than 93 °C 

24 [200 °F]}. Higher temperatures may be allowed if tests and/or calculations are provided to 

25 evaluate the reduction in strength and modulus of elasticity and these reductions are applied to 

26 the design calculations.  Acceptance criteria are described in Branch Technical Position (BTP) 

27 RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

28 3.5.2.2.1.3 Loss of Material Due to General, Pitting and Crevice Corrosion 

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

30 elements of inaccessible areas for all types of PWR and BWR containments. The 

31 existing program relies on ASME Section XI, Subsection IWE, and 10 CFR Part 50, 

32 Appendix J, to manage this aging effect. Further evaluation is recommended of 

33 plant-specific programs to manage this aging effect if corrosion is indicated from the IWE 

34 examinations. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this 

35 SRP-SLR Report). 

36 2. Loss of material due to general, pitting, and crevice corrosion could occur in steel torus 

37 shell of Mark I containments. The existing program relies on ASME Section XI, 

38 Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. If 

39 corrosion is significant, recoating of the torus is recommended. Acceptance criteria are 

40 described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

41 3. Loss of material due to general, pitting, and crevice corrosion could occur in steel torus 

42 ring girders and downcomers of Mark I containments, downcomers of Mark II 

43 containments, and interior surface of suppression chamber shell of Mark III 
3.5-4 

1 containments. The existing program relies on ASME Section XI, Subsection IWE to 

2 manage this aging effect. Further evaluation is recommended of plant-specific programs 

3 to manage this aging effect if corrosion is significant. Acceptance criteria are described 

4 in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

5 3.5.2.2.1.4 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and 

6 Elevated Temperature 

7 Loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for PWR 

8 prestressed concrete containments and BWR Mark II prestressed concrete containments is a 

9 time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required to be 

10 evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed 

11 separately in Section 4.5, “Concrete Containment Unbonded Tendon Pre-stress Analysis,” of 

12 this SRP-SLR Report. 

13 3.5.2.2.1.5 Cumulative Fatigue Damage 

14 If included in the CLB, fatigue analyses of metal liner, metal plates, suppression pool steel 

15 shells (including welded joints) and penetrations (including personnel airlock, equipment hatch, 

16 control rod drive (CRD) hatch, penetration sleeves, dissimilar metal welds, and penetration 

17 bellows) for all types of PWR and BWR containments and BWR vent header, vent line bellows, 

18 and downcomers are TLAAs as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

19 accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in 

20 Section 4.6, “Containment Liner Plates, Metal Containments, and Penetrations Fatigue 

21 Analysis,” of this SRP-SLR Report. 

22 3.5.2.2.1.6 Cracking Due to Stress Corrosion Cracking 

23 Stress corrosion cracking (SCC) of stainless steel (SS) penetration bellows and dissimilar metal 

24 welds could occur in all types of PWR and BWR containments. The existing program relies on 

25 ASME Section XI, Subsection IWE and10 CFR Part 50, Appendix J, to manage this aging 

26 effect. Further evaluation is recommended of additional appropriate examinations/evaluations 

27 implemented to detect these aging effects for SS penetration bellows and dissimilar 

28 metal welds. 

29 3.5.2.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw 

30 Loss of material (scaling, spalling) and cracking due to freeze-thaw could occur in inaccessible 

31 areas of PWR and BWR concrete containments. Further evaluation is recommended of this 

32 aging effect for plants located in moderate to severe weathering conditions. 

33 3.5.2.2.1.8 Cracking Due to Expansion From Reaction With Aggregates 

34 Cracking due to expansion from reaction with aggregates could occur in inaccessible areas of 

35 concrete elements of PWR and BWR concrete and steel containments. Further evaluation is 

36 recommended to determine if a plant-specific AMP is required to manage this aging effect. A 

37 plant-specific aging management program is not required if (1) as described in NUREG–1557, 

38 investigations, tests, and petrographic examinations of aggregates performed in accordance 

39 with American Society for Testing and Materials (ASTM) C295 and other ASTM reactivity tests, 

40 as required, can demonstrate that those aggregates do not adversely react within concrete, or 

41 (2) for potentially reactive aggregates, aggregate concrete reaction is not significant if it is 
3.5-5 

1 demonstrated that the in-place concrete can perform its intended function. Acceptance criteria 

2 are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

3 3.5.2.2.1.9 Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide 

4 and Carbonation 

5 Increase in porosity and permeability due to leaching of calcium hydroxide and carbonation 

6 could occur in inaccessible areas of concrete elements of PWR and BWR concrete and steel 

7 containments. Further evaluation is recommended if leaching is observed in accessible 

8 areas that impact intended functions. Acceptance criteria are described in BTP RLSB-1 

9 (Appendix A.1 of this SRP-SLR Report). 

10 3.5.2.2.2 Safety-Related and Other Structures and Component Supports 

11 3.5.2.2.2.1 Aging Management of Inaccessible Areas 

12 1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

13 below-grade inaccessible concrete areas of Groups 1–3, 5 and 7–9 structures. Further 

14 evaluation is recommended of this aging effect for inaccessible areas of these Groups of 

15 structures for plants located in moderate to severe weathering conditions. 

16 2. Cracking due to expansion and reaction with aggregates could occur in inaccessible 

17 concrete areas for Groups 1–5 and 7–9 structures. Further evaluation is recommended 

18 of inaccessible areas of these Groups of structures to determine if a plant-specific AMP 

19 is required to manage this aging effect. 

20 3. Cracking and distortion due to increased stress levels from settlement could occur in 

21 below-grade inaccessible concrete areas of structures for all Groups, and reduction in 

22 foundation strength, and cracking due to differential settlement and erosion of porous 

23 concrete subfoundations could occur in below-grade inaccessible concrete areas of 

24 Groups 1–3, 5–9 structures. The existing program relies on structure monitoring 

25 programs to manage these aging effects. Some plants may rely on a dewatering system 

26 to lower the site groundwater level. If the plant’s CLB credits a dewatering system, 

27 verification is recommended of the continued functionality of the dewatering system 

28 during the subsequent period of extended operation. No further evaluation is 

29 recommended if this activity is included in the scope of the applicant’s structures 

30 monitoring program. 

31 4. Increase in porosity and permeability, and loss of strength due to leaching of calcium 

32 hydroxide and carbonation could occur in below-grade inaccessible concrete areas of 

33 Groups 1–5 and 7–9 structures. Further evaluation is recommended if leaching is 

34 observed in accessible areas that impact intended functions. 

35 3.5.2.2.2.2 Reduction of Strength and Modulus Due to Elevated Temperature 

36 Reduction of strength and modulus of concrete due to elevated temperatures could occur in 

37 PWR and BWR Group 1–5 concrete structures. For any concrete elements that exceed 

38 specified temperature limits, further evaluations are recommended. Appendix A of American 

39 Concrete Institute (ACI) 349-85 specifies the concrete temperature limits for normal operation or 

40 any other long-term period. The temperatures shall not exceed 66 °C [150 °F] except for local 

41 areas, which are allowed to have increased temperatures not to exceed 93 °C [200°F]. Further 
3.5-6 

1 evaluation is recommended of a plant-specific program if any portion of the safety-related and 

2 other concrete structures exceeds specified temperature limits {i.e., general area temperature 

3 greater than 66 °C [150°F] and local area temperature greater than 93 °C [200 °F]}. Higher 

4 temperatures may be allowed if tests and/or calculations are provided to evaluate the reduction 

5 in strength and modulus of elasticity and these reductions are applied to the design calculations.  

6 The acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

7 3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures 

8 Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging 

9 effect combinations as identified below, whether or not they are covered by inspections in 

10 accordance with the GALL-SLR Report, AMP XI.S7, “Inspection of Water-Control Structures 

11 Associated with Nuclear Power Plants,” or Federal Energy Regulatory Commission 

12 (FERC)/U.S. Army Corp of Engineers dam inspection and maintenance procedures. 

13 1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

14 below-grade inaccessible concrete areas of Group 6 structures. Further evaluation is 

15 recommended of this aging effect for inaccessible areas for plants located in moderate 

16 to severe weathering conditions. 

17 2. Cracking due to expansion and reaction with aggregates could occur in inaccessible 

18 concrete areas of Group 6 structures. Further evaluation is recommended to determine 

19 if a plant-specific AMP is required to manage this aging effect. Acceptance criteria are 

20 described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

21 3. Increase in porosity and permeability and loss of strength due to leaching of calcium 

22 hydroxide and carbonation could occur in inaccessible areas of concrete elements of 

23 Group 6 structures. Further evaluation is recommended if leaching is observed in 

24 accessible areas that impact intended functions. Acceptance criteria are described in 

25 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

26 3.5.2.2.2.4 Cracking Due to Stress Corrosion Cracking, and Loss of Material Due to Pitting 

27 and Crevice Corrosion 

28 Cracking due to systems, structures, and components (SSC) and loss of material due to pitting 

29 and crevice corrosion could occur for Group 7 and 8 SS tank liners exposed to standing water. 

30 Further evaluation is recommended of plant-specific programs to manage these aging effects. 

31 The acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

32 3.5.2.2.2.5 Cumulative Fatigue Damage Due to Fatigue 

33 Fatigue of component support members, anchor bolts, and welds for Groups B1.1, B1.2, and 

34 B1.3 component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis 

35 exists. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The 

36 evaluation of this TLAA is addressed separately in Section 4.3, “Metal Fatigue Analysis,” of 

37 this SRP-SLR Report. 

38 3.5.2.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation 

39 Reduction of strength, loss of mechanical properties, and cracking due to irradiation could occur 

40 in PWR and BWR Group 4 concrete structures that are exposed to high levels of neutron and 
3.5-7 

1 gamma radiation. These structures include the reactor (primary/biological) shield wall, the 

2 sacrificial shield wall, and the reactor vessel support/pedestal structure. Data related to the 

3 effects and significance of neutron and gamma radiation on concrete mechanical and physical 

4 properties is limited, especially for conditions (dose, temperature, etc.) representative of 

5 light-water reactor (LWR) plants. However, based on literature review of existing research, 

radiation fluence limits of 1 × 1019 neutrons/cm2

 neutron radiation and 1 × 108 Gy [1 × 1010 6 rad] 

7 gamma dose are considered conservative radiation exposure levels beyond which concrete 

8 material properties may begin to degrade markedly (17, 18, 19). 

9 Further evaluation is recommended of a plant-specific program to manage aging effects of 

10 irradiation if the estimated (calculated) fluence levels or irradiation dose received by any portion 

11 of the concrete from neutron (fluence cutoff energy E > 0.1 MeV) or gamma radiation exceeds 

12 the respective threshold level during the subsequent period of extended operation or if 

13 plant-specific operating experience of concrete irradiation degradation exists that may impact 

14 intended functions. Higher fluence or dose levels may be allowed in the concrete if tests and/or 

15 calculations are provided to evaluate the reduction in strength and/or loss of mechanical 

16 properties of concrete from those fluence levels, at or above the operating temperature 

17 experienced by the concrete, and the effects are applied to the design calculations. Supporting 

18 calculations/analyses, test data, and other technical basis are provided to estimate and evaluate 

19 fluence levels and the plant-specific program. The acceptance criteria are described in 

20 BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

21 3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components 

22 Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR Report). 

23 3.5.2.2.4 Ongoing Review of Operating Experience 

24 Acceptance criteria are described in Appendix A.4, “Operating Experience for AMPs.” 

25 3.5.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

26 Generic Aging Lessons Learned for Subsequent License Renewal Report 

27 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

28 3.5.2.4 Aging Management Programs 

29 For those AMPs that will be used for aging management and are based on the program 

30 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

31 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

32 GALL-SLR Report, Chapter X, “Aging Management Programs That May Be Used to 

33 Demonstrate Acceptability of Time-Limited Aging Analyses in Accordance With Under 

34 10 CFR 54.21(c) (1)(iii),” and Chapter XI, “Chapter XI—Aging Management Programs.” 

35 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

36 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

37 10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

38 AMP with all exceptions would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

39 SLRA AMP, the reviewer identifies a difference from the GALL-SLR Report AMP that should 

40 have been identified as an exception to the GALL-SLR Report AMP, this difference should be 
3.5-8 

1 reviewed and properly dispositioned. The reviewer should document the disposition of all 

2 SLRA-defined exceptions and NRC staff-identified differences. 

3 The SLRA should identify any enhancements that are needed to permit an existing SLRA AMP 

4 to be declared consistent with the GALL-SLR AMP to which the SLRA AMP is compared. The 

5 reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

6 SLRA AMP to be consistent with the GALL-SLR AMP and that the applicant has a commitment 

7 in the FSAR supplement to implement the enhancement prior to the subsequent period of 

8 extended operation. The reviewer should document the disposition of all enhancements. 

9 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

10 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

11 (Appendix A.1.2.3 of this SRP-SLR Report). 

12 3.5.2.5 Final Safety Analysis Report Supplement 

13 The summary description of the programs and activities for managing the effects of aging for the 

14 subsequent period of extended operation in the FSAR supplement should be appropriate, such 

15 that later changes can be controlled by 10 CFR 50.59. The description should contain 

16 information associated with the bases for determining that aging effects are managed during the 

17 subsequent period of extended operation. The description should also contain any future aging 

18 management activities, including enhancements and commitments, to be completed before the 

19 subsequent period of extended operation. Table 3.0-1 of this SRP-SLR provides examples of 

20 the type of information to be included in the FSAR Supplement. Table 3.5-2 lists the programs 

21 that are applicable for this SRP-SLR subsection. 

22 3.5.3 Review Procedures 

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

24 3.5.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

25 Learned for Subsequent License Renewal Report 

26 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

27 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

28 approved in the GALL-SLR Report. The reviewer should not conduct a review of the substance 

29 of the matters described in the GALL-SLR Report. If the applicant has provided the information 

30 necessary to adopt the finding of program acceptability as described and evaluated in the 

31 GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to GALL-SLR 

32 in its SLRA. In making this determination, the reviewer confirms that the applicant has provided 

33 a brief description of the system, components, materials, and environment. The reviewer also 

34 confirms that the applicable aging effects have been addressed based on the staff’s review of 

35 industry and plant-specific operating experience. 

36 Furthermore, the reviewer should confirm that the applicant has addressed operating 

37 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

38 requires the reviewer to confirm that the applicant has identified those aging effects for the SC 

39 supports that are contained in the GALL-SLR Report as applicable to its plant. 
3.5-9 

1 3.5.3.2 Aging Management Review Results for Which Further Evaluation Is 

2 Recommended by the Generic Aging Lessons Learned for Subsequent License 

3 Renewal Report 

4 The basic review procedures defined in Section 3.5.3.1 need to be applied first for all of the 

5 AMRs and AMPs provided in this section. In addition, if the GALL-SLR AMR item to which the 

6 SLRA AMR item is compared identifies that further evaluation is recommended, then additional 

7 criteria apply for each of the following aging effect/aging mechanism combinations. 

8 3.5.3.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 

9 3.5.3.2.1.1 Cracking and Distortion Due to Increased Stress Levels From Settlement; 

10 Reduction of Foundation Strength and Cracking Due to Differential Settlement 

11 and Erosion of Porous Concrete Subfoundations 

12 Further evaluation is recommended of aging management of (1) cracking and distortion due to 

13 increases in component stress level from settlement for PWR and BWR concrete and steel 

14 containments and (2) reduction of foundation strength and cracking due to differential settlement 

15 and erosion of porous concrete subfoundations for all types of PWR and BWR containments if a 

16 dewatering system is relied upon to control settlement. The reviewer reviews and confirms that, 

17 if the applicant credits a dewatering system in its CLB, the applicant has committed to monitor 

18 the functionality of the dewatering system under the applicant’s ASME Code Section XI, 

19 Subsection IWL or the structures monitoring program. If not, the reviewer evaluates the 

20 plant-specific program for monitoring the dewatering system during the subsequent period of 

21 extended operation. 

22 3.5.3.2.1.2 Reduction of Strength and Modulus Due to Elevated Temperature 

23 Further evaluation is recommended of programs to manage reduction of strength and modulus 

24 of concrete due to elevated temperature for PWR and BWR concrete and steel containments. 

25 The implementation of ASME Section XI, Subsection IWL examinations and 10 CFR 50.55a 

26 would not be able to detect the reduction of concrete strength and modulus due to elevated 

27 temperature and also notes that no mandated aging management exists for managing this 

28 aging effect. 

29 A plant-specific evaluation should be performed if any portion of the concrete containment 

30 components exceeds specified temperature limits {i.e., general temperature greater than 66 °C 

31 [150°F] and local area temperature greater than 93 °C [200°F]}. Higher temperatures may be 

32 allowed if tests and/or calculations are provided to evaluate the reduction in strength and 

33 modulus of elasticity and these reductions are applied to the design calculations. The reviewer 

34 reviews and confirms that the applicant’s discussion in the renewal application indicates that the 

35 affected PWR and BWR containment components are not exposed to a temperature that 

36 exceeds the temperature limits. If active cooling is relied upon to maintain acceptable 

37 temperatures, then the reviewer ensures that the cooling system is being properly age-managed 

38 or temperatures are being monitored to identify a problem with the cooling system. If the limits 

39 are exceeded the reviewer reviews the technical basis (i.e., tests and/or calculations) provided 

40 by the applicant to justify the higher temperature. Otherwise, the reviewer reviews the 

41 applicant’s proposed programs to ensure that the effects of elevated temperature will be 

42 adequately managed during the subsequent period of extended. 
3.5-10 

1 3.5.3.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion 

2 1. The GALL-SLR Report identifies programs to manage loss of material due to general, 

3 pitting, and crevice corrosion in inaccessible areas of the steel elements in drywell and 

4 torus or the steel liner and integral attachments for all types of PWR and BWR 

5 containments. The AMP consists of ASME Section XI, Subsection IWE, and 

6 10 CFR Part 50, Appendix J, leak tests. Subsection IWE exempts from examination 

7 portions of the containments that are inaccessible, such as embedded or inaccessible 

8 portions of steel liners and steel elements in drywell and torus, and integral attachments. 

9 To cover the inaccessible areas, 10 CFR 50.55a(b)(2)(ix) requires that the applicant 

10 evaluate the acceptability of inaccessible areas when conditions exist in accessible 

11 areas that could indicate the presence of, or result in, degradation to such inaccessible 

12 areas. In addition, further evaluation of plant-specific programs to manage the aging 

13 effects for inaccessible areas is recommended if the following cannot be satisfied: 

14 (1) concrete meeting the requirements of ACI 318 or 349 and the guidance of 201.2R 

15 was used for the containment concrete in contact with the embedded containment shell 

16 or liner; (2) the moisture barrier, at the junction where the shell or liner becomes 

17 embedded, is subject to aging management activities in accordance with 

18 ASME Section XI, Subsection IWE requirements; (3) the concrete is monitored to ensure 

19 that it is free of penetrating cracks that provide a path for water seepage to the surface 

20 of the containment shell or liner; and (4) borated water spills and water ponding on the 

21 concrete floor are common and when detected are cleaned up or diverted to a sump in a 

22 timely manner. Operating experience has identified significant corrosion in some plants. 

23 If any of the above conditions cannot be satisfied, then a plant-specific AMP for 

24 corrosion is necessary. The reviewer reviews the applicant’s proposed AMP to confirm 

25 that, where appropriate, an effective inspection program has been developed and 

26 implemented to ensure that the aging effects in inaccessible areas are 

27 adequately managed. 

28 2. The GALL-SLR Report identifies programs to manage loss of material due to general, 

29 pitting, and crevice corrosion in steel torus shell of Mark I containments. The AMP 

30 consists of ASME Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J, leak 

31 tests. In addition, further evaluation is recommended of plant-specific programs to 

32 manage the aging effects if corrosion is significant. Further evaluation of torus shell 

33 corrosion is warranted as a result of industry-wide operating experience that identified a 

34 number of incidences of torus corrosion. The reviewer reviews the applicant’s proposed 

35 AMP to confirm that, where appropriate, an effective inspection program has been 

36 developed and implemented to ensure that the aging effects are adequately managed. 

37 A plant-specific program may include the recoating of the torus, if necessary. 

38 3. The GALL-SLR Report identifies programs to manage loss of material due to general, 

39 pitting, and crevice corrosion in steel torus ring girders and downcomers of Mark I 

40 containments, suppression chambers and downcomers of Mark II containments, and 

41 interior surface of suppression chamber shell of Mark III containments. GALL-SLR 

42 Report AMP XI.S1, “ASME Section XI, Subsection IWE,” is recommended for aging 

43 management. In addition, further evaluation of plant-specific programs is recommended 

44 to manage the aging effects if plant operating experience identified significant corrosion 

45 of the torus ring girders, downcomers and suppression chambers. 
3.5-11 

1 3.5.3.2.1.4 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and 

2 Elevated Temperature 

3 Loss of prestress is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

4 accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in 

5 Section 4.5 of this SRP-SLR. 

6 3.5.3.2.1.5 Cumulative Fatigue Damage 

7 Fatigue analyses included in the CLB for the containment liner plate, penetrations 

8 (including penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of 

9 PWR and BWR containments and BWR suppression pool steel shells, vent header, vent line 

10 bellows, and downcomers are TLAAs as defined in 10 CFR 54.3. TLAAs are required to be 

11 evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed 

12 separately in Section 4.6 of this SRP-SLR Report. 

13 3.5.3.2.1.6 Cracking Due to Stress Corrosion Cracking 

14 Further evaluation is recommended of programs to manage cracking due to SCC for SS 

15 penetration sleeves, dissimilar metal welds, and penetration bellows in all types of PWR and 

16 BWR containments. Transgranular stress corrosion cracking (TGSCC) is a concern for 

17 dissimilar metal welds. In the case of bellows assemblies, SCC may cause aging effects 

18 particularly if the material is not shielded from a corrosive environment. Containment inservice 

19 inspection (ISI) IWE and leak rate testing may not be sufficient to detect cracks, especially for 

20 dissimilar metal welds. Additional appropriate examinations to detect SCC in bellows 

21 assemblies and dissimilar metal welds are recommended to address this issue. The reviewer 

22 reviews and evaluates the applicant’s proposed programs to confirm that adequate inspection 

23 methods will be implemented to ensure that cracks are detected. 

24 3.5.3.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw 

25 Further evaluation is recommended of programs to manage loss of material (scaling, spalling) 

26 and cracking due to freeze-thaw for concrete elements of PWR and BWR containments. 

27 Containment ISI Subsection IWL may not be sufficient for plants located in moderate to severe 

28 weathering conditions. Evaluation is needed for plants that are located in moderate to severe 

29 weathering conditions (weathering index >100 day-inch/yr) (NUREG–1557). The weathering 

30 index for the continental United States is shown in ASTM C33-90, Figure 1. A plant-specific 

31 program is not required if documented evidence confirms that the existing concrete had air 

32 content of 3 percent to 8 percent (including tolerance) and subsequent inspection of accessible 

33 areas did not exhibit degradation related to freeze-thaw. Such inspections are considered a 

34 part of the evaluation. The reviewer reviews and confirms that the applicant has satisfied the 

35 recommendations for inaccessible concrete. Otherwise, the reviewer reviews the applicant’s 

36 proposed AMP to verify that, where appropriate, an effective inspection program has been 

37 developed and implemented to ensure that these aging effects in inaccessible areas for plants 

38 located in moderate to severe weathering conditions are adequately managed. 

39 3.5.3.2.1.8 Cracking Due to Expansion from Reaction With Aggregates 

40 Further evaluation is recommended of programs to manage cracking due to expansion and 

41 reaction with aggregates in inaccessible areas of concrete elements of PWR and BWR concrete 

42 and steel containments. A plant-specific AMP is necessary if (1) reactivity tests or petrographic 
3.5-12 

1 examinations of concrete samples identify reaction with aggregates, or (2) visual inspections of 

2 accessible concrete have identified indications of aggregate reactions, such as “map” or 

3 “patterned” cracking or the presence of reaction byproducts (e.g., alkali-silica gel). The reviewer 

4 confirms that the applicant has not identified one of the above conditions. Otherwise, the 

5 reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, an effective 

6 inspection program has been developed and implemented to ensure that this aging effect in 

7 inaccessible areas is adequately managed. 

8 3.5.3.2.1.9 Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide 

9 and Carbonation 

10 Further evaluation is recommended of programs to manage increase in porosity and 

11 permeability due to leaching of calcium hydroxide and carbonation in inaccessible areas of 

12 PWR and BWR concrete and steel containments. A plant-specific AMP is not required, even if 

13 reinforced concrete is exposed to flowing water if (1) there is evidence in the accessible areas 

14 that the flowing water has not caused leaching and carbonation, or (2) evaluation determined 

15 that the observed leaching of calcium hydroxide and carbonation in accessible areas has no 

16 impact on the intended function of the concrete structure. The reviewer confirms that the 

17 applicant has satisfied these conditions. Otherwise, the reviewer reviews the applicant’s 

18 proposed AMP to verify that, where appropriate, an effective inspection program has been 

19 developed and implemented to ensure that this aging effect in inaccessible areas is 

20 adequately managed. 

21 3.5.3.2.2 Safety-Related and Other Structures, and Component Supports 

22 3.5.3.2.2.1 Aging Management of Inaccessible Areas 

23 1. Further evaluation is recommended of programs to manage loss of material 

24 (spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete 

25 areas of Groups 1–3, 5, and 7–9 structures. Structure monitoring programs may not be 

26 sufficient for plants located in moderate to severe weathering conditions. Further 

27 evaluation is needed for plants that are located in moderate to severe weathering 

28 conditions (weathering index >100 day-inch/yr) (NUREG–1557). The weathering index 

29 for the continental United States is shown in ASTM C33-90, Figure 1. A plant-specific 

30 program is not required if documented evidence confirms that the existing concrete had 

31 air content of 3 percent to 8 percent and subsequent inspection did not exhibit 

32 degradation related to freeze-thaw. Such inspections should be considered a part of the 

33 evaluation. The reviewer confirms that the applicant has satisfied these conditions. 

34 Otherwise, the reviewer reviews the applicant’s proposed AMP to verify that, where 

35 appropriate, an effective inspection program has been developed and implemented to 

36 ensure that this aging effect in inaccessible areas for plants located in moderate to 

37 severe weathering conditions is adequately managed. 

38 2. Further evaluation is recommended to determine if a plant-specific program is required 

39 to manage cracking due to expansion from reaction with aggregates in inaccessible 

40 concrete areas of Groups 1–5 and 7–9 structures. A plant-specific program is required if 

41 (1) reactivity tests or petrographic examinations of concrete samples identify reaction 

42 with aggregates, or (2) visual inspections of accessible concrete have identified 

43 indications of aggregate reactions, such as “map” or “patterned” cracking or the 

44 presence of reaction byproducts (e.g., alkali-silica gel). The reviewer confirms that the 

45 applicant has not identified one of the above conditions. Otherwise, the reviewer 
3.5-13 

1 reviews the applicant’s proposed AMP to verify that, where appropriate, an effective 

2 inspection program has been developed and implemented to ensure that the aging effect 

3 is adequately managed. 

4 3. Further evaluation is recommended of aging management of (a) cracking and distortion 

5 due to increased stress levels from settlement for inaccessible concrete areas of 

6 structures for all Groups and (b) reduction of foundation strength, and cracking due to 

7 differential settlement and erosion of porous concrete subfoundations for inaccessible 

8 concrete areas of Groups 1–3, and 5–9 structures if a dewatering system is relied upon 

9 to manage the aging effect. The reviewer confirms that, if the applicant’s plant credits a 

10 dewatering system in its CLB, the applicant has committed to monitor the functionality of 

11 the dewatering system under the applicant’s structures monitoring program. If not, the 

12 reviewer reviews and evaluates the plant-specific program for monitoring the dewatering 

13 system during the subsequent period of extended operation. 

14 4. Further evaluation is recommended of programs to manage increase in porosity and 

15 permeability due to leaching of calcium hydroxide and carbonation in below-grade 

16 inaccessible concrete areas of Groups 1–5, and 7–9 structures. A plant-specific AMP is 

17 not required for the reinforced concrete exposed to flowing water if (1) there is evidence 

18 in the accessible areas that the flowing water has not caused leaching of calcium 

19 hydroxide and carbonation or (2) evaluation determined that the observed leaching of 

20 calcium hydroxide and carbonation in accessible areas has no impact on the intended 

21 function of the concrete structure. The reviewer confirms that the applicant has satisfied 

22 these conditions. Otherwise, the reviewer reviews the applicant’s proposed AMP to 

23 verify that, where appropriate, an effective inspection program has been developed 

24 and implemented to ensure that this aging effect in inaccessible areas is 

25 adequately managed. 

26 3.5.3.2.2.2 Reduction of Strength and Modulus Due to Elevated Temperature 

27 Further evaluation is recommended of programs to manage reduction of strength and modulus 

28 of concrete structures due to elevated temperature for PWR and BWR safety-related and 

29 other structures. 

30 A plant-specific evaluation should be performed if any portion of the concrete Groups 1–5 

31 structures exceeds specified temperature limits {i.e., general temperature greater than 66 °C 

32 [150 °F] and local area temperature greater than 93 °C [200 °F]}. Higher temperatures may be 

33 allowed if tests and/or calculations are provided to evaluate the reduction in strength and 

34 modulus of elasticity and these reductions are applied to the design calculations. The reviewer 

35 reviews and confirms that the applicant’s discussion in the renewal application indicates that the 

36 affected Groups 1–5 structures are not exposed to temperature that exceeds the temperature 

37 limits. If active cooling is relied upon to maintain acceptable temperatures, then the reviewer 

38 ensures that the cooling system is being properly age-managed or temperatures are being 

39 monitored to identify a problem with the cooling system. If the limits are exceeded the reviewer 

40 reviews the technical basis (i.e., tests and/or calculations) provided by the applicant to justify the 

41 higher temperature. Otherwise the reviewer reviews the applicant’s proposed programs on a 

42 case-by-case basis to ensure that the effects of elevated temperature will be adequately 

43 managed during the subsequent period of extended operation. 
3.5-14 

1 3.5.3.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures 

2 Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging 

3 effect combinations as identified below, whether or not they are covered by inspections in 

4 accordance with GALL-SLR Report AMP XI.S7, or FERC/US Army Corp of Engineers dam 

5 inspection and maintenance procedures. 

6 1. Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

7 below-grade inaccessible concrete areas of Group 6 structures. Further evaluation is 

8 needed for plants that are located in moderate to severe weathering conditions 

9 (weathering index >100 day-inch/yr) (NUREG–1557, Ref. 7). The weathering index for 

10 the continental U.S. is shown in ASTM C33-90, Figure 1. A plant-specific program is not 

11 required if documented evidence confirms that the existing concrete had air content of 

12 3 percent to 8 percent and subsequent inspection of accessible areas did not exhibit 

13 degradation related to freeze-thaw. Such inspections should be considered a part of the 

14 evaluation. The reviewer reviews and confirms that the applicant has satisfied these 

15 conditions. Otherwise, the reviewer reviews the applicant’s proposed AMP to determine 

16 that, where appropriate, an effective inspection program has been developed and 

17 implemented to ensure that this aging effect in inaccessible areas for plants located in 

18 moderate to severe weathering conditions will be adequately managed. 

19 2. Cracking due to expansion from reaction with aggregates could occur in inaccessible 

20 concrete areas of Group 6 structures. Further evaluation is recommended to determine 

21 if a plant-specific program is required to manage the aging effect. A plant specific 

22 program is required if (1) reactivity tests or petrographic examinations of concrete 

23 samples identify reaction with aggregates, or (2) visual inspections of accessible 

24 concrete have identified indications of aggregate reactions, such as “map” or “patterned” 

25 cracking or the presence of reaction byproducts (e.g., alkali-silica gel). The reviewer 

26 confirms that the applicant has not identified one of the above conditions. Otherwise, 

27 the reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, an 

28 effective inspection program has been developed and implemented to ensure that the 

29 aging effect will be adequately managed. 

30 3. Increase in porosity and permeability due to leaching of calcium hydroxide and 

31 carbonation could occur in below-grade inaccessible concrete areas of Group 6 

32 structures. Further evaluation is recommended to determine if a plant-specific program 

33 is required to manage the aging effect. A plant-specific program is not required for the 

34 reinforced structures exposed to flowing water if (1) there is evidence in the accessible 

35 areas that the flowing water has not caused leaching and carbonation, or (2) evaluation 

36 determined that the observed leaching of calcium hydroxide and carbonation in 

37 accessible areas has no impact on the intended function of the concrete structure. The 

38 reviewer confirms that the applicant has satisfied these conditions. Otherwise, the 

39 reviewer reviews the applicant’s proposed AMP to verify that, where appropriate, an 

40 effective inspection program has been developed and implemented to ensure that this 

41 aging effect in inaccessible areas will be adequately managed. 

42 3.5.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting 

43 and Crevice Corrosion 

44 Further evaluation is recommended of plant-specific programs to manage cracking due to SCC 

45 and loss of material due to pitting and crevice corrosion for SS tank liners exposed to standing 
3.5-15 

1 water. The reviewer reviews the applicant’s proposed AMP on a case-by-case basis to 

2 ensure that the intended functions will be maintained during the subsequent period of the 

3 extended operation. 

4 3.5.3.2.2.5 Cumulative Fatigue Damage 

5 Fatigue of support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 

6 component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. 

7 TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The evaluation of this 

8 TLAA is addressed separately in Section 4.3 of this SRP-SLR Report. 

9 3.5.3.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation 

10 Further evaluation is recommended of a plant-specific program to manage reduction of strength, 

11 loss of mechanical properties, and of concrete due to irradiation in PWR and BWR Group 4 

12 concrete structures, exposed to high levels of neutron and gamma radiation. These structures 

13 include the reactor (primary/biological) shield wall, the sacrificial shield wall, and the reactor 

14 vessel support/pedestal structure. The irradiation mechanism consists of radiation interactions 

15 with the material and heating due to absorption of radiation energy at the operating temperature 

16 experienced by the concrete. The intensity of radiation is typically characterized by the 

17 measure of its field or fluence. Both neutron and gamma radiation produce internal heating 

18 from absorption of radiation energy and, at high fluence levels, changes in microstructure and 

19 certain mechanical properties of concrete (e.g., compressive strength, tensile strength, modulus 

20 of elasticity) from radiation interactions with the material. Limited data are available in the 

21 open literature related to the effects and significance of radiation fluences (neutron and 

22 gamma radiation) on intended functions of concrete structures, especially for conditions 

23 (dose, temperature, etc.) representative of existing LWR plants. However, based on literature 

review of existing research, fluence limits of 1 × 1019 neutrons/cm2 24 neutron radiation and 

1 × 108

 Gy [1 × 1010 25 rad] gamma dose are considered conservative radiation exposure levels 

26 beyond which concrete material properties may begin to degrade markedly. 

27 Plant-specific calculations/analyses should be performed to identify the neutron (fluence cutoff 

28 energy E > 0.1 MeV) and gamma fields that develop in any portion of the concrete structures of 

29 interest at 80 years of operation and compare them to the above threshold limits. The impact of 

30 any plant-specific operating experience of concrete irradiation effects on intended functions are 

31 evaluated. The reviewer reviews these analyses, operating experience and supporting 

32 technical basis (e.g., calculations, test data) on a case-by-case basis. Higher fluence or dose 

33 levels may be allowed in the concrete if tests and/or calculations are provided to evaluate the 

34 reduction in strength and/or change in mechanical properties of concrete, if any, from those 

35 fluence levels and the effects are applied to the design calculations. The reviewer confirms that 

36 the applicant’s discussion in the SLRA indicates that the affected PWR and BWR concrete 

37 components are not exposed to neutron and gamma radiation fluence levels that exceed the 

38 threshold limits. The reviewer also confirms that the impact of any plant-specific operating 

39 experience of concrete irradiation degradation on intended functions is addressed. If the 

40 limits are exceeded, the technical basis (i.e., tests and/or calculations) provided by the 

41 applicant to justify higher fluence or dose limits is reviewed. Otherwise, the applicant’s 

42 proposed plant-specific program and the supporting technical basis is reviewed to ensure that 

43 the effects of irradiation on the concrete components will be adequately managed during 

44 the subsequent period of extended operation. 
3.5-16 

1 3.5.3.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components 

2 The applicant’s AMP for subsequent license renewal (SLR) should contain the elements of 

3 corrective actions, the confirmation process, and administrative controls. Safety-related 

4 components are covered by 10 CFR Part 50 Appendix B, which is adequate to address these 

5 program elements. However, Appendix B does not apply to nonsafety-related components that 

6 are subject to an AMR for SLR. Nevertheless, an applicant has the option to expand the scope 

7 of its 10 CFR Part 50 Appendix B program to include these components and address these 

8 program elements. If the applicant chooses this option, the reviewer verifies that the applicant 

9 has documented such a commitment in the FSAR supplement. If the applicant chooses 

10 alternative means, the branch responsible for quality assurance (QA) should be requested to 

11 review the applicant’s proposal on a case-by-case basis. 

12 3.5.3.2.4 Ongoing Review of Operating Experience 

13 The applicant’s AMPs should contain the element of operating experience. The reviewer 

14 verifies that the applicant has appropriate programs or processes for the ongoing review of both 

15 plant-specific and industry operating experience concerning age-related degradation and aging 

16 management. Such reviews are used to ensure that the AMPs are effective to manage the 

17 aging effects for which they are created. The AMPs are either enhanced or new AMPs are 

18 developed, as appropriate, when it is determined through the evaluation of operating experience 

19 that the effects of aging may not be adequately managed. Additional information is in 

20 Appendix A.4, “Operating Experience for Aging Management Programs.” 

21 In addition, the reviewer confirms that the applicant has provided an appropriate summary 

22 description of these activities in the FSAR supplement. An example description is under 

23 “Operating Experience” in Table 3.0-1, “FSAR Supplement for Aging Management of 

24 Applicable Systems.” 

25 3.5.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

26 Generic Aging Lessons Learned for Subsequent License Renewal Report 

27 The reviewer should confirm that the applicant, in their SLRA, has identified applicable aging 

28 effects, listed the appropriate combination of materials and environments, and credited AMPs 

29 that will adequately manage the aging effects. The AMP credited by the applicant could be an 

30 AMP that is described and evaluated in the GALL-SLR Report or a plant-specific program. 

31 Review procedures are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR Report). 

32 3.5.3.4 Aging Management Programs 

33 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

34 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

35 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

36 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

37 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

38 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

39 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

40 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP, with which 

41 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

42 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

43 enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 
3.5-17 

1 pertinent to the containments, SC supports are summarized in Table 3.5-1 of this SRP-SLR. 

2 The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR Report, 

3 Chapters II and III, presenting detailed information summarized by this row. 

4 Table 3.5-1 of this SRP-SLR may identify a plant-specific AMP. If the applicant chooses to use 

5 a plant-specific program that is not a GALL-SLR AMP, the NRC reviewer should confirm that 

6 the plant-specific program satisfies the criteria of BTP RLSB-1 (Appendix A.1.2.3 of this 

7 SRP-SLR Report). 

8 3.5.3.5 Final Safety Analysis Report Supplement 

9 The reviewer confirms that the applicant has provided in its FSAR supplement information 

10 equivalent to that in Table 3.0-1 for aging management of the containments, SC supports. 

11 Table 3.5-2 lists the AMPs that are applicable for this SRP-SLR subsection. The reviewer also 

12 confirms that the applicant has provided information for Subsection 3.5.3.3, “AMR Results Not 

13 Consistent With or Not Addressed in the GALL-SLR Report,” equivalent to that in Table 3.0-1. 

14 The NRC staff expects to impose a license condition on any renewed license to require the 

15 applicant to update its FSAR to include this FSAR supplement at the next update required 

16 pursuant to 10 CFR 50.71(e)(4). As part of the license condition until the FSAR update is 

17 complete, the applicant may make changes to the programs described in its FSAR supplement 

18 without prior NRC approval, provided that the applicant evaluates each such change and finds it 

19 acceptable pursuant to the criteria set forth in 10 CFR 50.59. If the applicant updates the 

20 FSAR to include the final FSAR supplement before the license is renewed, no condition will 

21 be necessary. 

22 As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

23 FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

24 the SLR application to any future aging management activities, including enhancements and 

25 commitments, to be completed before the subsequent period of extended operation. The NRC 

26 staff expects to impose a license condition on any renewed license to ensure that the applicant 

27 will complete these activities no later than the committed date. 

28 3.5.4 Evaluation Findings 

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

30 provisions of this section, then an evaluation finding similar to the following text should be 

31 included in the NRC staff’s safety evaluation report: 

32 On the basis of its review, as discussed above, the NRC staff concludes that the 

33 applicant has demonstrated that the aging effects associated with the 

34 containments, structures, and component supports components will be 

35 adequately managed so that the intended functions will be maintained consistent 

36 with the CLB for the subsequent period of extended operation, as required by 

37 10 CFR 54.21(a)(3). 

38 The NRC staff also reviewed the applicable FSAR Supplement program 

39 summaries and concludes that they adequately describe the AMPs credited 

40 for managing aging of the containments, structures, and component supports, as 

41 required by 10 CFR 54.21(d). 
3.5-18 

1 3.5.5 Implementation 

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

3 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

5 3.5.6 References 

6 1. 10 CFR Part 50, “Quality Assurance Criteria for Nuclear Power Plants.” Appendix B. 

7 Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

8 2. 10 CFR Part 50.55a, “Codes and Standards.” Washington, DC: U.S. Nuclear 

9 Regulatory Commission. 2015. 

10 3. 10 CFR Part 50.59, “Changes, Tests, and Experiments.” Washington, DC: U.S. Nuclear 

11 Regulatory Commission. 2015. 

12 4. 10 CFR Part 50, “Primary Reactor Containment Leakage Testing for Water-Cooled 

13 Power Reactors.” Appendix J. Washington, DC: U.S. Nuclear Regulatory Commission. 

14 2015. 

15 5. 10 CFR Part 50.71, “Maintenance of Record, Making of Reports.” Washington, DC: 

16 U.S. Nuclear Regulatory Commission. 2015. 

17 6. 10 CFR Part 50.65, “Requirements for Monitoring the Effectiveness of Maintenance at 

18 Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

19 7. 10 CFR 54.4, “Scope.” Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

20 8. NRC. Regulatory Guide 1.127, “Inspection of Water-Control Structures Associated with 

21 Nuclear Power Plants.” Revision 1. Washington, DC: U.S. Nuclear Regulatory 

22 Commission. March 1978. 

23 9. NEI. NEI 95-10, “Industry Guideline for Implementing the Requirements of 

24 10 CFR Part 54–The License Renewal Rule.” Revision 6. Washington, DC: Nuclear 

25 Energy Institute. 1995. 

26 10. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

27 Components,” Subsection IWL, “Requirements for Class CC Concrete Components of 

28 Light-Water Cooled Power Plants.” ASME Boiler and Pressure Vessel Code, 2004 

29 Edition. New York City, New York: American Society of Mechanical Engineers. 

30 11. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

31 Components,” Subsection IWE, “Requirements for Class MC and Metallic Liners of 

32 Class CC Components of Light-Water Cooled Power Plants.” ASME Boiler and 

33 Pressure Vessel Code, 2004 Edition. New York City, New York: American Society of 

34 Mechanical Engineers. 
3.5-19 

1 12. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant 

2 Components,” Subsection IWF, “Requirements for Class 1, 2, 3, and MC Component 

3 Supports of Light-Water Cooled Power Plants.” ASME Boiler and Pressure Vessel 

4 Code, 2004 Edition. New York City, New York: American Society of Mechanical 

5 Engineers. 

6 13. NEI. NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of 

7 Maintenance at Nuclear Power Plants.” Revision 2. Washington, DC: Nuclear Energy 

8 Institute. April 1996. 

9 14. NRC. Regulatory Guide 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear 

10 Power Plants.” Revision 2. ML003761662. March 31 1997. 

11 15. NRC. NUREG–1557, “Summary of Technical Information and Agreements from Nuclear 

12 Management and Resource Council Industry Report addressing License Renewal.” 

13 Washington, DC: U.S. Nuclear Regulatory Commission. October 1996. 

14 16. ACI. Standard 318, “Building Code Requirements for Reinforced Concrete and 

15 Commentary.” Farmington Hills, Michigan: American Concrete Institute. 

16 17. Hilsdorf, H.K., J. Kropp, and H.J. Koch. “The Effects of Nuclear Radiation on the 

17 Mechanical Properties of Concrete.” ACI SP 55-10. pp 223-251. 1978. 

18 18. NRC. NUREG/CR–7171, “A Review of the Effects of Radiation on Microstructure and 

19 Properties of Concretes Used in Nuclear Power Plants.” Washington, DC: U.S. Nuclear 

20 Regulatory Commission. November 2013 

21 19. Field, K.G., Y. Le Pape, and I. Remec. “Perspectives on Radiation Effects in Concrete 

22 for Nuclear Power Plants–Part I: Quantification of Radiation Exposure and Radiation 

23 Effects.” Nuclear Engineering and Design. Vol 285. pp 126–143. February 2015. 
3.5-20 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 1 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; buttresses, concrete elements, all 

Cracking and distortion due to increased stress levels from settlement 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.1.1) 

II.A1.CP-101 II.A2.CP-69 II.B1.2.CP-105 II.B2.2.CP-105 II.B3.1.CP-69 II.B3.2.CP-105 

M 2 BWR/PWR Concrete: foundation; 

subfoundation 

Reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete subfoundation 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.1.1) 

II.A1.C-07 II.A2.C-07 II.B1.2.C-07 II.B2.2.C-07 II.B3.1.C-07 II.B3.2.C-07 

M 3 BWR/PWR Concrete: dome; wall; 

basemat; ring girders; buttresses, concrete: containment; wall; basemat, concrete: basemat, concrete fill-in annulus 

Reduction of strength and modulus of elasticity due to elevated temperature (>150°F general; >200°F local) 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.2) 

II.A1.CP-34 II.B1.2.CP-57 II.B2.2.CP-57 II.B3.1.CP-65 II.B3.2.CP-108 

M 4 BWR Steel elements 

(inaccessible areas): drywell shell; drywell head 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.1) 

II.B3.1.CP-113 

M 5 BWR/PWR Steel elements 

(inaccessible areas): liner; liner anchors; integral attachments, steel elements (inaccessible areas): suppression chamber; drywell; drywell head; 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.1) 

II.A1.CP-98 II.A2.CP-98 II.B1.2.CP-63 II.B2.1.CP-63 II.B2.2.CP-63 II.B3.2.CP-98 
3.5-21 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

embedded shell; region shielded by diaphragm floor (as applicable) 

M 6 BWR Steel elements: torus 

shell 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.3.2) 

II.B1.1.CP-48 

M 7 BWR Steel elements: torus 

ring girders; downcomers;, Steel elements: suppression chamber shell (interior surface) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

Yes (SRP-SLR Section 3.5.2.2.1.3.3) 

II.B1.1.CP-109 II.B3.1.CP-158 

M 8 BWR/PWR Prestressing system: 

tendons 

Loss of prestress due to relaxation; shrinkage; creep; elevated temperature 

TLAA, SRP-SLR Section 4.5, "Concrete Containment Tendon Prestress" 

Yes (SRP-SLR Section 3.5.2.2.1.4) 

II.A1.C-11 II.B2.2.C-11 

M 9 BWR/PWR Personnel airlock, 

equipment hatch, CRD hatch, penetration sleeves; penetration bellows, steel elements: torus; vent line; vent header; vent line bellows; downcomers, suppression pool shell; unbraced downcomers, steel elements: vent header; downcomers 

Cumulative fatigue damage due to fatigue (Only if CLB fatigue analysis exists) 

TLAA, SRP-SLR Section 4.6, "Containment Liner Plate and Penetration Fatigue Analysis" 

Yes (SRP-SLR Section 3.5.2.2.1.5) 

II.A3.C-13 II.B1.1.C-21 II.B2.1.C-45 II.B2.2.C-48 II.B4.C-13 
3.5-22 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 10 BWR/PWR Penetration sleeves; 

penetration bellows 

Cracking due to stress corrosion cracking 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

Yes (SRP-SLR Section 3.5.2.2.1.6) 

II.A3.CP-38 II.B4.CP-38 

M 11 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses 

Loss of material (spalling, scaling) and cracking due to freezethaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.7) 

II.A1.CP-147 II.A2.CP-70 II.B3.2.CP-135 

M 12 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, containment, concrete fill-in annulus 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.8) 

II.A1.CP-67 II.A2.CP-104 II.B1.2.CP-99 II.B2.2.CP-99 II.B3.1.CP-83 II.B3.2.CP-121 

D 13 M 14 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, containment 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.1.9) 

II.A1.CP-102 II.A2.CP-53 II.B1.2.CP-110 II.B2.2.CP-110 II.B3.1.CP-53 II.B3.2.CP-122 

D 15 M 16 BWR/PWR Concrete (accessible 

areas): basemat, concrete: containment; 

Increase in porosity and permeability; cracking; loss of material 

AMP XI.S2, "ASME Section XI, Subsection IWL," 

No II.A1.CP-87 

II.A2.CP-72 II.B1.2.CP-106 
3.5-23 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

wall (spalling, scaling) due to 

aggressive chemical attack 

and/or AMP XI.S6, "Structures Monitoring" 

II.B2.2.CP-106 II.B3.1.CP-72 

D 17 M 18 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses 

Loss of material (spalling, scaling) and cracking due to freezethaw 

AMP XI.S2, "ASME Section XI, Subsection IWL" and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-31 

II.A2.CP-51 II.B3.2.CP-52 

M 19 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses, containment; concrete fill-in annulus 

Cracking due to expansion from reaction with aggregates 

AMP XI.S2, "ASME Section XI, Subsection IWL" and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-33 

II.A2.CP-58 II.B1.2.CP-59 II.B2.2.CP-59 II.B3.1.CP-66 II.B3.2.CP-60 

M 20 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses, containment 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S2, "ASME Section XI, Subsection IWL" 

No II.A1.CP-32 

II.A2.CP-155 II.B1.2.CP-54 II.B2.2.CP-54 II.B3.1.CP-156 II.B3.2.CP-55 

M 21 BWR/PWR Concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses; reinforcing steel 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S2, "ASME Section XI, Subsection IWL" and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-68 

II.A2.CP-74 II.B1.2.CP-79 II.B2.2.CP-79 II.B3.1.CP-74 II.B3.2.CP-88 
3.5-24 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

D 22 M 23 BWR/PWR Concrete (inaccessible 

areas): basemat; reinforcing steel, dome; wall 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-97 

II.A2.CP-75 II.B1.2.CP-80 II.B2.2.CP-80 II.B3.1.CP-75 II.B3.2.CP-89 

M 24 BWR/PWR Concrete (inaccessible 

areas): dome; wall; basemat; ring girders; buttresses, concrete (accessible areas): dome; wall; basemat 

Increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to aggressive chemical attack 

AMP XI.S2, "ASME Section XI, Subsection IWL," and/or AMP XI.S6, "Structures Monitoring" 

No II.A1.CP-100 

II.A2.CP-71 II.B3.1.CP-71 II.B3.2.CP-73 II.B3.2.CP-84 

D 25  26 BWR/PWR Moisture barriers 

(caulking, flashing, and other sealants) 

Loss of sealing due to wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.A3.CP-40 

II.B4.CP-40 

 27 BWR/PWR Penetration sleeves; 

penetration bellows, steel elements: torus; vent line; vent header; vent line bellows; downcomers, suppression pool shell 

Cracking due to cyclic loading (CLB fatigue analysis does not exist) 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-37 

II.B1.1.CP-49 II.B2.1.CP-107 II.B4.CP-37 
3.5-25 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 28 BWR/PWR Personnel airlock, 

equipment hatch, CRD hatch 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.C-16 

II.B4.C-16 

M 29 BWR/PWR Personnel airlock, 

equipment hatch, CRD hatch: locks, hinges, and closure mechanisms 

Loss of leak tightness due to mechanical wear 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-39 

II.B4.CP-39 

 30 BWR/PWR Pressure-retaining 

bolting 

Loss of preload due to self-loosening 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A3.CP-150 

II.B4.CP-150 

 31 BWR/PWR Pressure-retaining 

bolting, steel elements: downcomer pipes 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.A3.CP-148 

II.B1.2.CP-117 II.B2.1.CP-117 II.B2.2.CP-117 II.B4.CP-148 

 32 BWR/PWR Prestressing system: 

tendons; anchorage components 

Loss of material due to corrosion 

AMP XI.S2, "ASME Section XI, Subsection IWL" 

No II.A1.C-10 

II.B2.2.C-10 

 33 BWR/PWR Seals and gaskets Loss of sealing due to 

wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S4, "10 CFR Part 50, Appendix J " 

No II.A3.CP-41 

II.B4.CP-41 
3.5-26 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 34 BWR/PWR Service Level I coatings Loss of coating or lining 

integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage 

AMP XI.S8, "Protective Coating Monitoring and Maintenance" 

No II.A3.CP-152 

II.B4.CP-152 

M 35 BWR/PWR Steel elements 

(accessible areas): liner; liner anchors; integral attachments, penetration sleeves, drywell shell; drywell head; drywell shell in sand pocket regions; suppression chamber; drywell; embedded shell; region shielded by diaphragm floor (as applicable) 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.A1.CP-35 

II.A2.CP-35 II.A3.CP-36 II.B1.1.CP-43 II.B1.2.CP-46 II.B2.1.CP-46 II.B2.2.CP-46 II.B3.1.CP-43 II.B3.2.CP-35 II.B4.CP-36 

M 36 BWR Steel elements: drywell 

head; downcomers 

Loss of material due to mechanical wear, including fretting 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.B1.1.C-23 

II.B1.2.C-23 II.B2.1.C-23 II.B2.2.C-23 

 37 BWR Steel elements: 

suppression chamber (torus) liner (interior surface) 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.B1.2.C-49 

II.B2.2.C-49 

 38 BWR Steel elements: 

suppression chamber shell (interior surface) 

Cracking due to stress corrosion cracking 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, 

No II.B3.1.C-24 

II.B3.2.C-24 
3.5-27 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

Appendix J" 

 39 BWR Steel elements: vent line 

bellows 

Cracking due to stress corrosion cracking 

AMP XI.S1, "ASME Section XI, Subsection IWE," and AMP XI.S4, "10 CFR Part 50, Appendix J" 

No II.B1.1.CP-50 

 40 BWR Unbraced downcomers, 

steel elements: vent header; downcomers 

Cracking due to cyclic loading (CLB fatigue analysis does not exist) 

AMP XI.S1, "ASME Section XI, Subsection IWE" 

No II.B2.1.CP-142 

II.B2.2.CP-64 

M 41 BWR Steel elements: drywell 

support skirt, steel elements (inaccessible areas): support skirt 

None None No II.B1.1.CP-44 

II.B1.2.CP-114 II.B2.1.CP-114 II.B2.2.CP-114 

M 42 BWR/PWR Groups 1-3, 5, 7- 9: 

concrete (inaccessible areas): foundation 

Loss of material (spalling, scaling) and cracking due to freezethaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.1) 

III.A1.TP-108 III.A2.TP-108 III.A3.TP-108 III.A5.TP-108 III.A7.TP-108 III.A8.TP-108 III.A9.TP-108 

M 43 BWR/PWR All Groups except Group 

6: concrete (inaccessible areas): all 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.2) 

III.A1.TP-204 III.A2.TP-204 III.A3.TP-204 III.A4.TP-204 III.A5.TP-204 III.A7.TP-204 III.A8.TP-204 III.A9.TP-204 
3.5-28 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 44 BWR/PWR All Groups: concrete: all Cracking and distortion 

due to increased stress levels from settlement 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.2.1.3) 

III.A1.TP-30 III.A2.TP-30 III.A3.TP-30 III.A4.TP-304 III.A5.TP-30 III.A6.TP-30 III.A7.TP-30 III.A8.TP-30 III.A9.TP-30 

D 45 M 46 BWR/PWR Groups 1-3, 5-9: 

concrete: foundation; subfoundation 

Reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete subfoundation 

AMP XI.S6, "Structures Monitoring" 

Yes (SRP-SLR Section 3.5.2.2.2.1.3) 

III.A1.TP-31 III.A2.TP-31 III.A3.TP-31 III.A5.TP-31 III.A6.TP-31 III.A7.TP-31 III.A8.TP-31 III.A9.TP-31 

M 47 BWR/PWR Groups 1-5, 7-9: 

concrete (inaccessible areas): exterior aboveand below-grade; foundation 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.1.4) 

III.A1.TP-67 III.A2.TP-67 III.A3.TP-67 III.A4.TP-305 III.A5.TP-67 III.A7.TP-67 III.A8.TP-67 III.A9.TP-67 

M 48 BWR/PWR Groups 1-5: concrete: all Reduction of strength 

and modulus due to elevated temperature (>150°F general; 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.2) 

III.A1.TP-114 III.A2.TP-114 III.A3.TP-114 III.A4.TP-114 
3.5-29 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

>200°F local) III.A5.TP-114 

M 49 BWR/PWR Groups 6 - concrete 

(inaccessible areas): exterior above- and below-grade; foundation; interior slab 

Loss of material (spalling, scaling) and cracking due to freezethaw 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.1) 

III.A6.TP-110 

M 50 BWR/PWR Groups 6: concrete 

(inaccessible areas): all 

Cracking due to expansion from reaction with aggregates 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.2) 

III.A6.TP-220 

M 51 BWR/PWR Groups 6: concrete 

(inaccessible areas): exterior above- and below-grade; foundation; interior slab 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.3.3) 

III.A6.TP-109 

M 52 BWR/PWR Groups 7, 8 - steel 

components: tank liner 

Cracking due to stress corrosion cracking; Loss of material due to pitting and crevice corrosion 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.4) 

III.A7.T-23 III.A8.T-23 

M 53 BWR/PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Cumulative fatigue damage due to fatigue (Only if CLB fatigue analysis exists) 

TLAA, SRP-SLR Section 4.3 "Metal Fatigue" 

Yes (SRP-SLR Section 3.5.2.2.2.5) 

III.B1.1.T-26 III.B1.2.T-26 III.B1.3.T-26 

 54 BWR/PWR All groups except 6: 

concrete (accessible areas): all 

Cracking due to expansion from reaction with aggregates 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-25 

III.A2.TP-25 III.A3.TP-25 III.A4.TP-25 III.A5.TP-25 III.A7.TP-25 
3.5-30 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

III.A8.TP-25 III.A9.TP-25 

M 55 BWR/PWR Building concrete at 

locations of expansion and grouted anchors; grout pads for support base plates 

Reduction in concrete anchor capacity due to local concrete degradation/ serviceinduced cracking or other concrete aging mechanisms 

AMP XI.S6, "Structures Monitoring" 

No III.B1.1.TP-42 

III.B1.2.TP-42 III.B1.3.TP-42 III.B2.TP-42 III.B3.TP-42 III.B4.TP-42 

M 56 BWR/PWR Concrete: exterior 

above- and belowgrade; foundation; interior slab 

Loss of material due to abrasion; cavitation 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.T-20 

M 57 BWR/PWR Constant and variable 

load spring hangers; guides; stops 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.T-28 

III.B1.2.T-28 III.B1.3.T-28 

M 58 BWR/PWR Earthen water-control 

structures: dams; embankments; reservoirs; channels; canals and ponds 

Loss of material; loss of form due to erosion, settlement, sedimentation, frost action, waves, currents, 

AMP XI.S7, "Inspection of Water-Control Structures Associated with 

No III.A6.T-22 
3.5-31 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

surface runoff, seepage Nuclear Power 

Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

M 59 BWR/PWR Group 6: concrete 

(accessible areas): all 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-38 

M 60 BWR/PWR Group 6: concrete 

(accessible areas): exterior above- and below-grade; foundation 

Loss of material (spalling, scaling) and cracking due to freezethaw 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-36 
3.5-32 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 61 BWR/PWR Group 6: concrete 

(accessible areas): exterior above- and below-grade; foundation; interior slab 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-37 

M 62 BWR/PWR Group 6: Wooden Piles; 

sheeting 

Loss of material; change in material properties due to weathering, chemical degradation, and insect infestation repeated wetting and drying, fungal decay 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-223 

 63 BWR/PWR Groups 1-3, 5, 7-9: 

concrete (accessible areas): exterior aboveand below-grade; foundation 

Increase in porosity and permeability; loss of strength due to leaching of calcium hydroxide and carbonation 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-24 

III.A2.TP-24 III.A3.TP-24 III.A5.TP-24 III.A7.TP-24 III.A8.TP-24 III.A9.TP-24 
3.5-33 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 64 BWR/PWR Groups 1-3, 5, 7-9: 

concrete (accessible areas): exterior aboveand below-grade; foundation 

Loss of material (spalling, scaling) and cracking due to freezethaw 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-23 

III.A2.TP-23 III.A3.TP-23 III.A5.TP-23 III.A7.TP-23 III.A8.TP-23 III.A9.TP-23 

 65 BWR/PWR Groups 1-3, 5, 7-9: 

concrete (inaccessible areas): below-grade exterior; foundation, Groups 1-3, 5, 7-9: concrete (accessible areas): below-grade exterior; foundation, Groups 6: concrete (inaccessible areas): all 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-212 

III.A1.TP-27 III.A2.TP-212 III.A2.TP-27 III.A3.TP-212 III.A3.TP-27 III.A5.TP-212 III.A5.TP-27 III.A6.TP-104 III.A7.TP-212 III.A7.TP-27 III.A8.TP-212 III.A8.TP-27 III.A9.TP-212 III.A9.TP-27 

 66 BWR/PWR Groups 1-5, 7, 9: 

concrete (accessible areas): interior and above-grade exterior 

Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-26 

III.A2.TP-26 III.A3.TP-26 III.A4.TP-26 III.A5.TP-26 III.A7.TP-26 III.A9.TP-26 

 67 BWR/PWR Groups 1-5, 7, 9: 

Concrete: interior; above-grade exterior, Groups 1-3, 5, 7-9 - 

Increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-28 

III.A1.TP-29 III.A2.TP-28 III.A2.TP-29 
3.5-34 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

concrete (inaccessible areas): below-grade exterior; foundation, Group 6: concrete (inaccessible areas): all 

aggressive chemical attack 

III.A3.TP-28 III.A3.TP-29 III.A4.TP-28 III.A5.TP-28 III.A5.TP-29 III.A6.TP-107 III.A7.TP-28 III.A7.TP-29 III.A8.TP-29 III.A9.TP-28 III.A9.TP-29 

 68 BWR/PWR High-strength structural 

bolting 

Cracking due to stress corrosion cracking 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-41 

M 69 BWR/PWR High-strength structural 

bolting 

Cracking due to stress corrosion cracking 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-300 

III.A2.TP-300 III.A3.TP-300 III.A4.TP-300 III.A5.TP-300 III.A7.TP-300 III.A8.TP-300 III.A9.TP-300 III.B2.TP-300 III.B3.TP-300 III.B4.TP-300 

 70 BWR/PWR Masonry walls: all Cracking due to restraint 

shrinkage, creep, aggressive environment 

AMP XI.S5, "Masonry Walls" 

No III.A1.T-12 

III.A2.T-12 III.A3.T-12 III.A5.T-12 III.A6.T-12 
3.5-35 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 71 BWR/PWR Masonry walls: all Loss of material 

(spalling, scaling) and cracking due to freezethaw 

AMP XI.S5, "Masonry Walls" 

No III.A1.TP-34 

III.A2.TP-34 III.A3.TP-34 III.A5.TP-34 III.A6.TP-34 

M 72 BWR/PWR Seals; gasket; moisture 

barriers (caulking, flashing, and other sealants) 

Loss of sealing due to wear, damage, erosion, tear, surface cracks, other defects 

AMP XI.S6, "Structures Monitoring" 

No III.A6.TP-7 

 73 BWR/PWR Service Level I coatings Loss of coating or lining 

integrity due to blistering, cracking, flaking, peeling, delamination, rusting, or physical damage 

AMP XI.S8, "Protective Coating Monitoring and Maintenance" 

No III.A4.TP-301 

M 74 BWR/PWR Sliding support bearings; 

sliding support surfaces 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-46 

III.B2.TP-47 III.B4.TP-46 III.B4.TP-47 

M 75 BWR/PWR Sliding surfaces Loss of mechanical 

function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-45 

III.B1.2.TP-45 III.B1.3.TP-45 

M 76 BWR/PWR Sliding surfaces: radial 

beam seats in BWR drywell 

Loss of mechanical function due to corrosion, distortion, dirt or debris accumulation, overload, wear 

AMP XI.S6, "Structures Monitoring" 

No III.A4.TP-35 
3.5-36 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 77 BWR/PWR Steel components: all 

structural steel 

Loss of material due to corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-302 

III.A2.TP-302 III.A3.TP-302 III.A4.TP-302 III.A5.TP-302 III.A7.TP-302 III.A8.TP-302 

M 78 BWR/PWR Stainless steel fuel pool 

liner 

Cracking due to stress corrosion cracking; Loss of material due to pitting and crevice corrosion 

AMP XI.M2, "Water Chemistry," and monitoring of the spent fuel pool water level and leakage from the leak chase channels. 

No III.A5.T-14 

 79 BWR/PWR Steel components: piles Loss of material due to 

corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A3.TP-219 

M 80 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-248 

III.A2.TP-248 III.A3.TP-248 III.A4.TP-248 III.A5.TP-248 III.A6.TP-248 III.A7.TP-248 III.A8.TP-248 III.A9.TP-248 III.B2.TP-248 III.B3.TP-248 III.B4.TP-248 
3.5-37 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 81 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-226 

III.B1.2.TP-226 III.B1.3.TP-226 

M 82 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-274 

III.A2.TP-274 III.A3.TP-274 III.A4.TP-274 III.A5.TP-274 III.A7.TP-274 III.A8.TP-274 III.A9.TP-274 III.B2.TP-274 III.B3.TP-274 III.B4.TP-274 

M 83 BWR/PWR Structural bolting Loss of material due to 

general, pitting, crevice corrosion 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. 

No III.A6.TP-221 

D 84 
3.5-38 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 85 BWR/PWR Structural bolting Loss of material due to 

pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-232 

III.B1.2.TP-232 III.B1.3.TP-232 

 86 BWR/PWR Structural bolting Loss of material due to 

pitting, crevice corrosion 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-235 

III.B1.2.TP-235 III.B1.3.TP-235 

 87 BWR/PWR Structural bolting Loss of preload due to 

self-loosening 

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-229 

III.B1.2.TP-229 III.B1.3.TP-229 

M 88 BWR/PWR Structural bolting Loss of preload due to 

self-loosening 

AMP XI.S6, "Structures Monitoring" 

No III.A1.TP-261 

III.A2.TP-261 III.A3.TP-261 III.A4.TP-261 III.A5.TP-261 III.A6.TP-261 III.A7.TP-261 III.A8.TP-261 III.A9.TP-261 III.B2.TP-261 III.B3.TP-261 III.B4.TP-261 

M 89 PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Loss of material due to boric acid corrosion 

AMP XI.M10, "Boric Acid Corrosion" 

No III.B1.1.T-25 

III.B1.1.TP-3 III.B1.2.T-25 III.B1.3.TP-3 III.B1.2.TP-3 III.B2.T-25 III.B2.TP-3 III.B3.T-25 
3.5-39 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

III.B3.TP-3 III.B4.T-25 III.B4.TP-3 

M 90 BWR/PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Loss of material due to general (steel only), pitting, crevice corrosion 

AMP XI.M2, "Water Chemistry," and AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.TP-10 

 91 BWR/PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Loss of material due to general, pitting corrosion

AMP XI.S3, "ASME Section XI, Subsection IWF" 

No III.B1.1.T-24 

III.B1.2.T-24 III.B1.3.T-24 

M 92 BWR/PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Loss of material due to general, pitting corrosion

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-43 

III.B3.TP-43 III.B4.TP-43 

 93 BWR/PWR Support members; 

welds; bolted connections; support anchorage to building structure 

Loss of material due to pitting, crevice corrosion 

AMP XI.S6, "Structures Monitoring" 

No III.B2.TP-6 

III.B4.TP-6 

M 94 BWR/PWR Vibration isolation 

elements 

Reduction or loss of isolation function due to radiation hardening, temperature, humidity, sustained vibratory loading 

AMP XI.S3, "ASME Section XI, Subsection IWF" and/or AMP XI.S6, "Structures Monitoring" 

No III.B1.1.T-33 

III.B1.2.T-33 III.B1.3.T-33 III.B4.TP-44 
3.5-40 

Table 3.5-1. Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in 

Chapters II and III of the GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component 

Aging 

Effect/Mechanism 

Aging 

Management 

Program 

(AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 95 BWR/PWR Aluminum, galvanized 

steel and stainless steel support members; welds; bolted connections; support anchorage to building structure exposed to air – indoor uncontrolled 

None None No III.B1.1.TP-4 

III.B1.1.TP-8 III.B1.2.TP-4 III.B1.2.TP-8 III.B1.3.TP-4 III.B1.3.TP-8 III.B2.TP-4 III.B2.TP-8 III.B3.TP-4 III.B3.TP-8 III.B4.TP-4 III.B4.TP-8 

N 96 BWR/PWR Groups 6: concrete 

(accessible areas): all 

Cracking due to expansion from reaction with aggregates 

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants" 

No III.A6.T-34 

N 97 BWR/PWR Group 4: Concrete 

(reactor cavity area proximate to the reactor vessel): reactor (primary/biological) shield wall; sacrificial shield wall; reactor vessel support/pedestal structure 

Reduction of strength; loss of mechanical properties due to irradiation (i.e., radiation interactions with material and radiationinduced heating) 

Plant-specific aging management program 

Yes (SRP-SLR Section 3.5.2.2.2.6) 

III.A4.T-35 
3.5-41 

Table 3.5-2. AMPs and Additional Guidance Appendices Recommended for 

Containments, Structures, and Component Supports 

GALL-SLR Report Chapter/AMP Program Name 

Chapter XI.M2 Water Chemistry 

Chapter XI.M10 Boric Acid Corrosion 

Chapter XI.M18 Bolting Integrity 

Chapter XI.S1 ASME Section XI, Subsection IWE 

Chapter XI.S2 ASME Section XI, Subsection IWL 

Chapter XI.S3 ASME Section XI, Subsection IWF 

Chapter XI.S4 10 CFR Part 50, Appendix J 

Chapter XI.S5 Masonry Walls 

Chapter XI.S6 Structures Monitoring 

Chapter XI.S7 Inspection of Water-Control Structures Associated with 

Nuclear Power Plants 

Chapter XI.S8 Protective Coating Monitoring and Maintenance 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLSB-1) 

3.6-1 

1 3.6 Aging Management of Electrical and Instrumentation and Controls 

2 Review Responsibilities 

3 Primary—Branches assigned responsibility by Project Manager (PM) as described in this 

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

5 Power Plants (SRP-SLR) Section 3.0. 

6 3.6.1 Areas of Review 

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

8 management programs (AMPs) of the electrical and instrumentation and control (I&C). For a 

9 recent vintage plant, the information related to the electrical and I&C is contained in Chapter 7, 

10 “Instrumentation and Controls,” and Chapter 8, “Electric Power,” of the plant’s Final Safety 

11 Analysis Report (FSAR), consistent with the “Standard Review Plan for the Review of Safety 

12 Analysis Reports for Nuclear Power Plants” (NUREG–0800) (Ref. 1). For older plants, the 

13 location of applicable information is plant-specific because an older plant’s FSAR may have 

14 predated NUREG–0800. Typical electrical and I&C components that are subject to an AMR for 

15 subsequent license renewal (SLR) are electrical cables and connections, metal enclosed buses, 

16 cable bus, fuse holders, high-voltage insulators, transmission conductors and connections, and 

17 switchyard bus and connections. 

18 The responsible review organization is to review the following subsequent license renewal 

19 application (SLRA) AMR and AMP items assigned to it, per SRP-SLR Section 3.0: 

20 AMRs 

21  AMR results consistent with the Generic Aging Lessons Learned for Subsequent 

22 License Renewal (GALL-SLR) Report 

23  AMR results for which further evaluation is recommended 

24  AMR results not consistent with or not addressed in the GALL-SLR Report 

25 AMPs 

26  Consistent with GALL-SLR Report AMPs 

27  Plant-specific AMPs 

28 FSAR Supplement 

29  The responsible review organization is to review the FSAR Supplement associated with 

30 each assigned AMP. 

31 3.6.2 Acceptance Criteria 

32 The acceptance criteria for the areas of review describe methods for determining whether the 

33 applicant has met the requirements of the U.S. Nuclear Regulatory Commissions (NRC) 

34 regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21.
3.6-2 

1 3.6.2.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

2 Learned for Subsequent License Renewal Report 

3 The AMRs and the AMPs applicable to the electrical and I&C components are described and 

4 evaluated in Chapter VI of the Generic Aging Lessons Learned (GALL-SLR) Report. 

5 The applicant’s SLRA should provide sufficient information for the NRC reviewer to confirm that 

6 the specific SLRA AMR item and the associated SLRA AMP are consistent with the cited 

7 GALL-SLR Report AMR item. The reviewer should then confirm that the SLRA AMR item is 

8 consistent with the GALL-SLR Report AMR item to which it is compared. 

9 When the applicant is crediting a different AMP than recommended in the GALL-SLR Report, 

10 the reviewer should confirm that the alternate AMP is valid to use for aging management and 

11 will be capable of managing the effects of aging as adequately as the AMP recommended by 

12 the GALL-SLR Report. 

13 3.6.2.2 Aging Management Review Results for Which Further Evaluation Is 

14 Recommended by the Generic Aging Lessons Learned for Subsequent License 

15 Renewal Report 

16 The basic acceptance criteria defined in Section 3.6.2.1 need to be applied first for all of the 

17 AMRs and AMPs reviewed as part of this section. In addition, if the GALL-SLR Report AMR 

18 item to which the SLRA AMR item is compared identifies that “further evaluation is 

19 recommended,” then additional criteria apply as identified by the GALL-SLR Report for each of 

20 the following aging effect/aging mechanism combinations. Refer to Table 3.6-1, comparing the 

21 “Further Evaluation Recommended” and the “GALL-SLR Item” column, for the AMR items that 

22 reference the following subsections. 

23 3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

24 Environmental qualification is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. 

25 TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The evaluation of 

26 this TLAA is addressed separately in Section 4.4, “Environmental Qualification (EQ) of Electrical 

27 Equipment,” of this SRP-SLR. 

28 3.6.2.2.2 Reduced Insulation Resistance Due to Loss of Material Due to General, Pitting, 

29 and Crevice Corrosion, Loosening of Bolts Caused by Thermal Cycling and 

30 Ohmic Heating, Degradation Caused Thermal/Thermoxidative Degradation of 

31 Organics and Photolysis (UV Sensitive Materials Only) of Organics, 

32 Moisture/Debris Intrusion and Ohmic Heating 

33 Reduced insulation resistance due to loss of material due to general, pitting, and crevice 

34 corrosion, loosening of bolts caused by thermal cycling and ohmic heating, degradation caused 

35 thermal/thermoxidative degradation of organics and photolysis [ultraviolet (UV) sensitive 

36 materials only] of organics and moisture/debris intrusion could occur in cable bus assemblies. 

37 The GALL-SLR Report recommends further evaluation of a plant-specific Cable Bus AMP to 

38 ensure that this aging effect is adequately managed. Acceptance criteria are described in 

39 Branch Technical Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR). 
3.6-3 

1 3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion, Loss of Conductor Strength Due 

2 to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss 

3 of Preload 

4 Loss of material due to wind-induced abrasion, loss of conductor strength due to corrosion, and 

5 increased resistance of connection due to oxidation or loss of preload could occur in 

6 transmission conductors and connections, and in switchyard bus and connections. The 

7 GALL-SLR Report recommends further evaluation of a plant-specific AMP to ensure that this 

8 aging effect is adequately managed. Acceptance criteria are described in BTP RLSB-1 

9 (Appendix A.1 of this SRP-SLR). 

10 3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

11 Acceptance criteria are described in BTP IQMB-1 (Appendix A.2 of this SRP-SLR). 

12 3.6.2.2.5 Ongoing Review of Operating Experience 

13 Acceptance criteria are described in Appendix A.4, “Operating Experience for AMPs.” 

14 3.6.2.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

15 Generic Aging Lessons Learned for Subsequent License Renewal Report 

16 Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

17 3.6.2.4 Aging Management Programs 

18 For those AMPs that will be used for aging management and that are based on the program 

19 elements of an AMP in the GALL-SLR Report, the NRC reviewer performs an audit of AMPs 

20 credited in the SLRA to confirm consistency with the GALL-SLR AMPs identified in the 

21 GALL-SLR Report, Chapters X and XI. 

22 If the applicant identifies an exception to any of the program elements of the cited GALL-SLR 

23 Report AMP, the SLRA AMP should include a basis demonstrating how the criteria of 

24 10 CFR 54.21(a)(3) would still be met. The NRC reviewer should then confirm that the SLRA 

25 AMP, with all exceptions, would satisfy the criteria of 10 CFR 54.21(a)(3). If, while reviewing the 

26 SLRA AMP, the reviewer identifies a difference between the SLRA AMP and the GALL-SLR 

27 Report AMP that should have been identified as an exception to the GALL-SLR Report AMP, 

28 the difference should be reviewed and properly dispositioned. The reviewer should document 

29 the disposition of all SLRA-defined exceptions and NRC staff-identified differences. 

30 The SLRA should identify any enhancements that are needed to permit an existing AMP to be 

31 declared consistent with the GALL-SLR Report AMP to which the SLRA AMP is compared. The 

32 reviewer is to confirm both that the enhancement, when implemented, would allow the existing 

33 plant AMP to be consistent with the GALL-SLR Report AMP and also that the applicant has a 

34 commitment in the FSAR supplement to implement the enhancement prior to the subsequent 

35 period of extended operation. The reviewer should review and document the disposition of 

36 all enhancements. 

37 If the applicant chooses to use a plant-specific program that is not a GALL-SLR AMP, the NRC 

38 reviewer should confirm that the plant-specific program satisfies the criteria of BTP RLSB-1 

39 (Appendix A.1 of this SRP-SLR). 
3.6-4 

1 3.6.2.5 Final Safety Analysis Review Supplement 

2 The summary description of the programs and activities for managing the effects of aging for the 

3 subsequent period of extended operation in the FSAR supplement should be sufficiently 

4 comprehensive, such that later changes can be controlled by 10 CFR 50.59. The description 

5 should contain information associated with the bases for determining that aging effects are 

6 managed during the subsequent period of extended operation. The description should also 

7 contain any future aging management activities, including commitments, license conditions, 

8 enhancements, and exceptions, to be implemented prior to or during the subsequent period of 

9 extended operation. Table 3.0-1 of this SRP-SLR provides examples of the type of information 

10 to be included in the FSAR Supplement. Table 3.6-2 lists the programs that are applicable for 

11 this SRP-SLR subsection. 

12 3.6.3 Review Procedures 

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

14 3.6.3.1 Aging Management Review Results Consistent With the Generic Aging Lessons 

15 Learned for Subsequent License Renewal Report 

16 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate, and 

17 demonstrate that the AMRs and AMPs at its facility are consistent with those reviewed and 

18 approved in the GALL-SLR Report. The reviewer should not conduct a re-review of the 

19 substance of the matters described in the GALL-SLR Report. If the applicant has provided the 

20 information necessary to adopt the finding of program acceptability as described and evaluated 

21 in the GALL-SLR Report, the reviewer should find acceptable the applicant’s reference to the 

22 GALL-SLR Report in its SLRA. In making this determination, the reviewer confirms that the 

23 applicant has provided a brief description of the system, components, materials, and 

24 environment. The reviewer also confirms that the applicable aging effects, have been 

25 addressed based on the staff’s review of industry and plant-specific operating experience. 

26 Furthermore, the reviewer should confirm that the applicant has addressed operating 

27 experience identified after the issuance of the GALL-SLR Report. Performance of this review 

28 includes confirming that the applicant has identified those aging effects for the electrical and I&C 

29 components that are contained in the GALL-SLR Report as applicable to its plant. 

30 3.6.3.2 Aging Management Review Results for Which Further Evaluation Is 

31 Recommended by the Generic Aging Lessons Learned for Subsequent License 

32 Renewal Report 

33 The basic review procedures defined in Section 3.6.3.1 need to be applied first for all of the 

34 AMRs and AMPs provided in this section. In addition, if the GALL-SLR AMR item to which the 

35 SLRA AMR item is compared identifies that “further evaluation is recommended,” then 

36 additional criteria apply as identified by the GALL-SLR Report for each of the following aging 

37 effect/aging mechanism combinations. 

38 3.6.3.2.1 Electrical Equipment Subject to Environmental Qualification 

39 Environmental qualification is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be 

40 evaluated in accordance with 10 CFR 54.21(c)(1). The NRC staff reviews the evaluation of this 

41 TLAA separately following the guidance in Section 4.4 of this SRP-SLR. 
3.6-5 

1 3.6.3.2.2 Reduced Insulation Resistance Due to Loss of Material Due to General, Pitting, 

2 and Crevice Corrosion, Loosening of Bolts Caused by Thermal Cycling and 

3 Ohmic Heating, Degradation Caused by Thermal/Thermoxidative Degradation of 

4 Organics and Photolysis (UV Sensitive Materials Only) of Organics, 

5 Moisture/Debris Intrusion and Ohmic Heating 

6 The GALL SLR Report recommends a plant-specific Cable Bus AMP for the management of 

7 reduced insulation resistance due to loss of material due to general, pitting, and crevice 

8 corrosion, loosening of bolts caused by thermal cycling and ohmic heating, degradation caused 

9 thermal/thermoxidative degradation of organics and photolysis (UV sensitive materials only) of 

10 organics and moisture/debris intrusion. The reviewer reviews the applicant’s proposed program 

11 on a case-by-case basis to ensure that an adequate program will be in place for the 

12 management of these aging effects. 

13 3.6.3.2.3 Loss of Material Due to Wind-Induced Abrasion, Loss of Conductor Strength Due 

14 to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss 

15 of Preload 

16 The GALL-SLR Report recommends a plant-specific AMP for the management of loss of 

17 material due to wind-induced abrasion, loss of conductor strength due to corrosion, and 

18 increased resistance of connection due to oxidation or loss of preload in transmission 

19 conductors and connections, and in switchyard bus and connections. The reviewer reviews the 

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

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

22 3.6.3.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

23 The applicant’s AMPs for SLR should contain the elements of corrective actions, the 

24 confirmation process, and administrative controls. Safety-related components are covered by 

25 10 CFR Part 50, Appendix B, which is adequate to address these program elements. However, 

26 Appendix B does not apply to nonsafety-related components that are subject to an AMR for 

27 SLR. Nevertheless, the applicant has the option to expand the scope of its 10 CFR Part 50, 

28 Appendix B program to include these components and address these program elements. If the 

29 applicant chooses this option, the reviewer confirms that the applicant has documented such a 

30 commitment in the FSAR supplement. If the applicant chooses alternative means, the 

31 branch responsible for quality assurance (QA) should be requested to review the applicant’s 

32 proposal on a case-by-case basis. 

33 3.6.3.2.5 Ongoing Review of Operating Experience 

34 The applicant’s AMPs should contain the element of operating experience. The reviewer 

35 verifies that the applicant has appropriate programs or processes for the ongoing review of both 

36 plant-specific and industry operating experience concerning age-related degradation and aging 

37 management. Such reviews are used to ensure that the AMPs are effective to manage the 

38 aging effects for which they are created. The AMPs are either enhanced or new AMPs are 

39 developed, as appropriate, when it is determined through the evaluation of operating experience 

40 that the effects of aging may not be adequately managed. Additional information is in 

41 Appendix A.4, “Operating Experience for Aging Management Programs.” 

42 In addition, the reviewer confirms that the applicant has provided an appropriate summary 

43 description of these activities in the FSAR supplement. An example description is under 
3.6-6 

1 “Operating Experience” in Table 3.0-1, “FSAR Supplement for Aging Management of 

2 Applicable Systems.” 

3 3.6.3.3 Aging Management Review Results Not Consistent With or Not Addressed in the 

4 Generic Aging Lessons Learned for Subsequent License Renewal Report 

5 The reviewer should confirm that the applicant, in the SLR application, has identified applicable 

6 aging effects, listed the appropriate combination of materials and environments, and has 

7 credited AMPs that will adequately manage the aging effects. The AMP credited by the 

8 applicant could be an AMP that is described and evaluated in the GALL-SLR Report or in a 

9 plant-specific program. Review procedures are described in BTP RLSB-1 (Appendix A.1 of this 

10 SRP-SLR). 

11 3.6.3.4 Aging Management Programs 

12 The reviewer confirms that the applicant has identified the appropriate AMPs as described and 

13 evaluated in the GALL-SLR Report. If the applicant commits to an enhancement to make its 

14 SLRA AMP consistent with a GALL-SLR Report AMP, then the reviewer is to confirm that this 

15 enhancement, when implemented, will make the SLRA AMP consistent with the GALL-SLR 

16 Report AMP. If the applicant identifies, in the SLRA AMP, an exception to any of the program 

17 elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the 

18 exception will satisfy the criteria of 10 CFR 54.21(a)(3). If the reviewer identifies a difference, 

19 not identified by the SLRA, between the SLRA AMP and the GALL-SLR Report AMP with which 

20 the SLRA claims to be consistent, the reviewer should confirm that the SLRA AMP with this 

21 difference satisfies 10 CFR 54.21(a)(3). The reviewer should document the basis for accepting 

22 enhancements, exceptions, or differences. The AMPs evaluated in the GALL-SLR Report 

23 pertinent to the electrical and I&C components are summarized in Table 3.6-1 of this SRP-SLR. 

24 The “GALL-SLR Item” column identifies the AMR item numbers in the GALL-SLR Report, 

25 Chapters VI, presenting detailed information summarized by this row. 

26 Table 3.6-1 of this SRP-SLR may identify a plant-specific AMP. If the applicant chooses to use 

27 a plant-specific program that is not a GALL-SLR AMP, the NRC reviewer should confirm that the 

28 plant-specific program satisfies the criteria of BTP RLSB-1 (Appendix A.1 of this SRP-SLR). 

29 3.6.3.5 Final Safety Analysis Report Supplement 

30 The reviewer confirms that the applicant has provided in its FSAR supplement information 

31 equivalent to that in Table 3.0-1 for aging management of the Electrical and I&C System. 

32 Table 3.6-2 lists the AMPs that are applicable for this SRP-SLR subsection. The reviewer also 

33 confirms that the applicant has provided information for Subsection 3.6.3.3, “AMR Results Not 

34 Consistent With or Not Addressed in the GALL-SLR Report,” equivalent to that in Table 3.0-1. 

35 The applicant updates its FSAR to include this FSAR supplement at the next update required 

36 pursuant to 10 CFR 50.71(e)(4). 

37 As noted in Table 3.0-1, an applicant need not incorporate the implementation schedule into its 

38 FSAR. However, the reviewer should confirm that the applicant has identified and committed in 

39 the SLRA to any future aging management activities, including enhancements, exception, and 

40 commitments to be completed prior to or during the subsequent period of extended operation.
3.6-7 

1 3.6.4 Evaluation Findings 

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

3 provisions of this section, then an evaluation finding similar to the following text should be 

4 included in the NRC staff’s safety evaluation report: 

5 On the basis of its review the NRC staff concludes that the applicant has demonstrated that the 

6 aging effects associated with the electrical and I&C components will be adequately managed so 

7 that the intended functions will be maintained consistent with the current licensing basis for the 

8 subsequent period of extended operation, as required by 10 CFR 54.21(a)(3). 

9 The NRC staff also reviewed the applicable FSAR Supplement program summary descriptions 

10 and concludes that they adequately describe the AMPs credited for managing aging of electrical 

11 and I&C, as required by 10 CFR 54.21(d). 

12 3.6.5 Implementation 

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

14 complying with specified portions of the NRC’s regulations, the method described herein will be 

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

16 3.6.6 References 

17 1. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

18 for Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

19 March 2007. 
3.6-8 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 1 BWR/PWR Electrical equipment 

subject to 10 CFR 50.49 EQ requirements composed of various polymeric and metallic materials in plant areas subject to a harsh environment (i.e., loss of coolant accident (LOCA), high energy line break (HELB), or post LOCA environment or; An adverse localized environment for the most limiting qualified condition for temperature, radiation, or moisture for the component material (e.g., cable or connection insulation). 

Various aging effects due to various mechanisms in accordance with 10 CFR 50.49 

EQ is a time-limited aging analysis (TLAA) to be evaluated for the subsequent period of extended operation. See the Standard Review Plan, Section 4.4, "Environmental Qualification (EQ) of Electrical Equipment," for acceptable methods for meeting the requirements of 10 CFR 54.21(c)(1)(i) and (ii). See AMP X.E1, "Environmental Qualification (EQ) of Electric Components," of this report for meeting the requirements of 10 CFR 54.21(c)(1)(i)-(iii). See Standard Review Plan, Section 4.4, "Environmental Qualification (EQ) of Electrical Equipment and AMP X.E1, "Environmental Qualification (EQ) of Electric Components," of this report for meeting 

Yes, TLAA (See subsection 3.6.2.2.1) 

VI.B.L-05 
3.6-9 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

the requirements of 10CFR 54.21(c)(1)(iii). 

M 2 BWR/PWR High-voltage 

electrical insulators composed of porcelain; malleable iron; aluminum; galvanized steel; cement exposed to air – outdoor 

Loss of material due to mechanical wear caused by movement of transmission conductors due to significant wind 

AMP XI.E7, "High Voltage Insulators" A plant-specific aging management program is to be evaluated 

No VI.A.LP-32 

M 3 BWR/PWR High-voltage 

insulators composed of porcelain; malleable iron; aluminum; galvanized steel; cement exposed to air – outdoor 

Reduced electrical insulation resistance due to presence of salt deposits or surface contamination 

AMP XI.E7, "High Voltage Insulators" 

No) VI.A.LP-28 

 4 BWR/PWR Transmission 

conductors composed of aluminum; steel exposed to air – outdoor 

Loss of conductor strength due to corrosion 

A plant-specific aging management program is to be evaluated for ACSR 

Yes, plantspecific (See subsection 3.6.2.2.3) 

VI.A.LP-38 

M 5 BWR/PWR Transmission 

connectors composed of aluminum; steel exposed to air – outdoor 

Increased electrical resistance of connection due to oxidation or loss of pre-load 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.3) 

VI.A.LP-48 
3.6-10 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

M 6 BWR/PWR Switchyard bus and 

connections composed of Aluminum; copper; bronze; stainless steel; galvanized steel exposed to air – outdoor 

Loss of material due to wind-induced abrasion; Increased electrical resistance of connection due to oxidation or loss of pre-load 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.3) 

VI.A.LP-39 

 7 BWR/PWR Transmission 

conductors composed of aluminum; steel exposed to air – outdoor 

Loss of material due to wind-induced abrasion 

A plant-specific aging management program is to be evaluated for ACAR and ACSR 

Yes, plantspecific (See subsection 3.6.2.2.3) 

VI.A.LP-47 

M 8 BWR/PWR Electrical insulation 

for electrical cables and connections (including terminal blocks, etc.) composed of various organic polymers (e.g., EPR, SR, EPDM, XLPE) exposed to an adverse localized environment caused by heat, radiation, or moisture 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis (UV sensitive materials only) of organics; radiationinduced oxidation; moisture intrusion 

AMP XI.E1, "Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-33 

M 9 BWR/PWR Electrical insulation 

for electrical cables and connections used in instrumentation 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis 

AMP XI.E2, "Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

No VI.A.LP-34 
3.6-11 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

circuits that are sensitive to reduction in conductor insulation resistance (IR) composed of various organic polymers (e.g., EPR, SR, EPDM, XLPE) exposed to an adverse localized environment caused by heat, radiation, or moisture 

(UV sensitive materials only) of organics; radiationinduced oxidation; moisture intrusion 

Qualification Requirements Used in Instrumentation Circuits" 

M 10 BWR/PWR Electrical conductor 

insulation for inaccessible power, instrumentation, and control cables (e.g., installed in conduit or direct buried) composed of various organic polymers (e.g., EPR, SR, EPDM, XLPE) exposed to an adverse localized environment caused by significant moisture 

Reduced electrical insulation resistance due to moisture 

AMPs XI.E3A, XI.E3B, and XI.E3C, "Inaccessible Power Instrumentation, and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-35 

 11 BWR/PWR Metal enclosed bus: 

enclosure assemblies composed of elastomers exposed 

Surface cracking, crazing, scuffing, dimensional change (e.g. "ballooning" and "necking"), shrinkage, 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.M38, "Inspection of Internal Surfaces in 

No VI.A.LP-29 
3.6-12 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

to air – indoor controlled or uncontrolled, air – outdoor 

discoloration, hardening and loss of strength due to elastomer degradation 

Miscellaneous Piping and Ducting Components" 

M 12 BWR/PWR Metal enclosed bus: 

bus/connections composed of various metals used for electrical bus and connections exposed to air – indoor controlled or uncontrolled, air – outdoor 

Increased electrical resistance of connection due to the loosening of bolts caused by thermal cycling and ohmic heating 

AMP XI.E4, "Metal Enclosed Bus" 

No VI.A.LP-25 

M 13 BWR/PWR Metal enclosed bus: 

electrical insulation; insulators composed of porcelain; xenoy; thermo-plastic organic polymers exposed to air – indoor controlled or uncontrolled, air – outdoor 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics/thermoplastics , radiation-induced oxidation, moisture/debris intrusion, and ohmic heating 

AMP XI.E4, "Metal Enclosed Bus" 

No VI.A.LP-26 

 14 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies composed of steel exposed to air – indoor uncontrolled, air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.S6, "Structures Monitoring" 

No VI.A.LP-43 
3.6-13 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

 15 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies composed of galvanized steel; aluminum exposed to air – outdoor 

Loss of material due to pitting, crevice corrosion 

AMP XI.E4, "Metal Enclosed Bus," or AMP XI.S6, "Structures Monitoring" 

No VI.A.LP-42 

M 16 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to air – indoor uncontrolled 

Increased electrical resistance of connection due to chemical contamination, corrosion, and oxidation. (in an air, indoor controlled environment, increased resistance of connection due to chemical contamination, corrosion and oxidation do not apply); 

AMP XI.E5, "Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are located in an environment that does not subject them to environmental aging mechanisms and effects due to chemical contamination, corrosion, and oxidation. 

No VI.A.LP-23 

N 17 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to air-indoor controlled or uncontrolled 

Increased electrical resistance of connection due to fatigue from ohmic heating, thermal cycling, electrical transients 

AMP XI.E5, Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are not subject to fatigue due to ohmic heating, thermal cycling, electrical 

No VI.A.L-07 
3.6-14 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

transients 

M 18 BWR/PWR Fuse holders (not 

part of active equipment): metallic clamps composed of various metals used for electrical connections exposed to air – indoor controlled or uncontrolled 

Increased electrical resistance of connection due to fatigue caused by frequent fuse removal/manipulation or vibration 

AMP XI.E5, "Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are not subject to fatigue caused by frequent fuse removal/manipulation or vibration 

No VI.A.LP-31 

M 19 BWR/PWR Cable connections 

(metallic parts) composed of various metals used for electrical contacts exposed to air – indoor controlled or uncontrolled, air – outdoor 

Increased electrical resistance of connection due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation 

AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 

No VI.A.LP-30 

M 20 PWR Electrical connector 

contacts for electrical connectors composed of various metals used for electrical contacts exposed to air with borated water 

Increased electrical resistance of connection due to corrosion of connector contact surfaces caused by intrusion of borated water 

AMP XI.M10, "Boric Acid Corrosion" 

No VI.A.LP-36 
3.6-15 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

leakage 

M 21 BWR/PWR Transmission 

conductors composed of aluminum exposed to air – outdoor 

Loss of conductor strength due to corrosion 

None - for Aluminum Conductor Aluminum Alloy Reinforced (ACAR) and All Aluminum Conductor (AAC) 

None VI.A.LP-46 

M 22 BWR/PWR Fuse holders (not 

part of active equipment): insulation material composed of electrical insulation material: bakelite; phenolic melamine or ceramic; molded polycarbonate, and other, exposed to air – indoor controlled or uncontrolled 

Reduced electrical insulation resistance due to thermal/thermoxidative degradation of organics, radiolysis, and photolysis (UV sensitive materials only) of organics; radiationinduced oxidation; moisture intrusion 

AMP XI.E5, "Fuse Holders" No aging management program is required for those applicants who can demonstrate these fuse holders are located in an environment that does not subject them to environmental aging mechanisms 

No VI.A.LP-24 

N 23 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies. Galvanized steel; aluminum. air – indoor controlled or uncontrolled 

None None No VI.A.LP-41 
3.6-16 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 24 BWR/PWR Metal enclosed bus: 

external surface of enclosure assemblies. Steel air – indoor controlled 

None None No VI.A.LP-44 

N 26 BWR/PWR Cable bus: enclosure 

assemblies composed of elastomers exposed to air – indoor controlled or uncontrolled, air – outdoor 

Surface cracking, crazing, scuffing, dimensional change (e.g. "ballooning" and "necking"), shrinkage, discoloration, hardening and loss of strength due to elastomer degradation 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.2) 

VI.A.L-08 

N 27 BWR/PWR Cable bus: external 

surface of enclosure assemblies galvanized steel; aluminum; air – indoor controlled or uncontrolled 

None None No VI.A.L-09 

N 28 BWR/PWR Cable bus: 

bus/connections composed of various metals used for electrical bus connections exposed to air – indoor controlled or uncontrolled, air – outdoor 

Increased electrical resistance of connection due to the loosening of bolts caused by thermal cycling and ohmic heating 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.2) 

VI.A.L-10 
3.6-17 

Table 3.6-1. Summary of Aging Management Programs for the Electrical Components Evaluated in Chapter VI of the 

GALL-SLR Report 

New (N), 

Modified 

(M), 

Deleted 

(D) Item ID Type Component Aging Effect/Mechanism 

Aging Management 

Program (AMP)/TLAA 

Further 

Evaluation 

Recommended 

GALL-SLR 

Item 

N 29 BWR/PWR Cable bus: electrical 

insulation; insulators – exposed to air – indoor controlled or uncontrolled, air – outdoor 

Reduced electrical insulation resistance due to degradation caused thermal/thermoxidative degradation of organics and photolysis (UV sensitive materials only) of organics, moisture/debris intrusion and ohmic heating 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.2) 

VI.A.L-11 

N 30 BWR/PWR Cable bus: external 

surface of enclosure assemblies composed of steel exposed to air – indoor uncontrolled or air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.2) 

VI.A.L-12 

N 31 BWR/PWR Cable bus external 

surface of enclosure assemblies composed of galvanized steel; aluminum exposed to air – outdoor 

Loss of material due to general, pitting, crevice corrosion 

A plant-specific aging management program is to be evaluated 

Yes, plantspecific (See subsection 3.6.2.2.2) 

VI.A.L-13 

N 32 BWR/PWR Cable bus: external 

surface of enclosure assemblies: composed of steel; air – indoor controlled 

None None No VI.A.L-14 
3.6-18 

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

and Instrumentation and Control Systems 

GALL-SLR Report Chapter/AMP Program Name 

AMP X.E1 Environmental Qualification of Electric Components 

AMP XI.E1 Electrical Insulation for Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements 

AMP XI.E2 Electrical Insulation for Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits 

AMP XI.E3A Electrical Insulation for Inaccessible Medium Voltage 

Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements 

AMP XI.E3B Electrical Insulation for Inaccessible Instrument and 

Control Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements 

AMP XI.E3C Electrical Insulation for Inaccessible Low Voltage Power 

Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

AMP XI.E4 Metal Enclosed Bus 

AMP XI.E5 Fuse Holders 

AMP XI.E6 Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

AMP XI.E7 High Voltage Insulators 

AMP XI.M10 Boric Acid Corrosion 

AMP XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components 

AMP XI.S6 Structures Monitoring 

GALL-SLR Report Appendix A Quality Assurance for Aging Management Programs 

GALL-SLR Report Appendix B Operating Experience for Aging Management Programs 

SRP-SLR Appendix A.1 Aging Management Review—Generic (Branch Technical 

Position RLBS-1) 
4.1-1 

1 4 TIME-LIMITED AGING ANALYSES 

2 4.1 Identification of Time-Limited Aging Analyses and Exemptions 

3 Review Responsibilities 

4 Primary—Branch responsible for the time-limited aging analysis (TLAA) issues 

5 Secondary—Other branches responsible for engineering, as appropriate 

6 4.1.1 Areas of Review 

7 This review plan section addresses the identification of TLAAs. The technical review of TLAAs 

8 is addressed in Sections 4.2 through 4.7. As explained in more detail below, the list of TLAAs 

9 are certain plant-specific safety analyses that are defined, in part, by the current operating 

10 term. Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1), a license 

11 renewal applicant is required to provide a list of TLAAs, as defined in 10 CFR 54.3. The area 

12 relating to the identification of TLAAs is reviewed. 

13 TLAAs may have developed since issuance of a plant’s operating license. As indicated in 

14 10 CFR 54.30, the adequacy of the plant’s current licensing basis (CLB), which includes TLAAs, 

15 is not an area within the scope of the license renewal review. Any questions regarding the 

16 adequacy of the CLB are addressed under the backfit rule (10 CFR 50.109) and are separate 

17 from the license renewal process. 

18 In addition, pursuant to 10 CFR 54.21(c)(2), an applicant must provide a list of plant-specific 

19 exemptions granted under 10 CFR 50.12 that are based on TLAAs. The U.S. Nuclear 

20 Regulatory Commission (NRC) staff should focus its review to confirm that the applicant did 

21 not omit any TLAAs, as defined in 10 CFR 54.3. 

22 Pursuant to 10 CFR 54.21(d), each application includes a final safety analysis report 

23 (FSAR), updated final safety analysis report (UFSAR), or updated safety analysis 

24 report (USAR), as appropriate for the CLB supplement summary description for each 

25 TLAA that is identified in accordance with 10 CFR 54.3. 

26 4.1.2 Acceptance Criteria 

27 The acceptance criteria for the areas of review described in Subsection 4.1.1 of this review 

28 plan section delineate acceptable methods for meeting the requirements of the NRC’s 

29 regulations in 10 CFR 54.21(c)(1). For the applicant’s list of exemptions to be acceptable 

30 under the requirement in 10 CFR 54.21(c)(2), the NRC staff should have reasonable 

31 assurance that there has been no omission of TLAAs from the subsequent license renewal 

32 application (SLRA) that were used as the basis for receiving NRC approval of regulatory 

33 exemptions granted in accordance with 10 CFR 50.12 requirements. 

34 TLAAs are those licensee calculations and analyses that meet all six of the following criteria, as 

35 defined in 10 CFR 54.3(a): 

36 1. Involve systems, structures, and components within the scope of license 

37 renewal, as delineated in 10 CFR 54.4(a); 
4.1-2 

1 2. Consider the effects of aging; 

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

3 example, 40 years; 

4 4. Were determined to be relevant by the licensee in making a safety determination; 

5 5. Involve conclusions or provide the basis for conclusions related to the capability 

6 of the system, structure, or component to perform its intended function(s), as 

7 delineated in 10 CFR 54.4(b); and 

8 6. Are contained or incorporated by reference in the CLB. 

9 The TLAA identification criterion in Criterion 1 is based only on a comparison to the scoping 

10 requirements in 10 CFR 54.4 and therefore does not limit the applicability of TLAAs only to 

11 those components that would be required to be screened in for an AMP in accordance with the 

12 requirement in 10 CFR 54.21(a)(1). Thus, the possibility exists that, for a given CLB, a TLAA 

13 may need to be identified for a given active component if the analysis in the CLB is determined 

14 to be in conformance with all six of the criteria in 10 CFR 54.3(a) for identifying an analysis as a 

15 TLAA. Fatigue flaw growth analyses of pressurized water reactor (PWR) reactor coolant pump 

16 flywheels are examples of plant-specific analyses that apply to an active component type and 

17 may need to be identified as a TLAA for a given application. 

18 The applicant’s FSAR (as updated) identifies TLAAs that were incorporated by reference into 

19 the CLB. In addition, for subsequent license renewal (SLR) applications, there may be 

20 situations where an analysis of record was not required to be identified as a TLAA for the 

21 current operating period (as approved in the renewed operating license for the facility), but will 

22 need to be identified as a TLAA for a proposed subsequent period of extended operation, as 

23 required by the regulation in 10 CFR 54.21(c)(1). Specifically, criterion 3 for TLAAs in 

24 10 CFR 54.3(a) establishes that to be a TLAA the analysis has to involve time-limited 

25 assumptions defined by the current operating term. In Federal Register Notice (FRN) 

26 No. 95-11136, Volume 60, Number 88, dated May 8, 1995 (Ref. 3), the NRC identified that 

27 TLAAs are those: 

28 analyses with (i) time-related assumptions, (ii) utilized in determining the acceptability 

29 of SSCs, within the scope of license renewal (as defined in 10 CFR 54.4), (iii) which 

30 are based upon a period of plant operation equal to or greater than the current 

31 license term, but less than the cumulative period of plant operation (viz., the existing 

32 license term plus the period of extended operation requested in the renewed 

33 application). 

34 For example, for an existing analysis that is part of the CLB and is based on a 60-year time 

35 assumption, the analysis would not necessarily have to be identified as a TLAA for the initial 

36 license renewal request because it would not conform to the definition of a TLAA, as clarified in 

37 FRN No. 95-11136; however, if the same analysis was left unchanged in the CLB and was 

38 going to be relied upon for a proposed SLR period, the analysis would conform to the third 

39 criterion for TLAAs in 10 CFR 54.3(a) because the 60-year assumed life would form the updated 

40 current operating term basis for the proposed SLR period. 

41 The reviewer reviews the FSAR supplement for each TLAA identified as being within the scope 

42 of the SLRA, as defined in 10 CFR 54.3. 
4.1-3 

1 4.1.3 Review Procedures 

2 For each area of review described in Subsection 4.1.1, the reviewer adheres to the following 

3 review procedures: 

4 The reviewer uses the plant FSAR (as updated) and other CLB documents, such as NRC staff 

5 safety evaluation report (SERs), to perform the review. The reviewer selects analyses that the 

6 applicant did not identify as TLAAs that are likely to meet the six criteria identified in 

7 Subsection 4.1.2. The reviewer verifies that the selected analyses, not identified by the 

8 applicant as TLAAs, do not meet at least one of the following criteria: 

9 Sections 4.2 through 4.6 identify typical types of TLAAs for most plants. Information on the 

10 applicant’s methodology for identifying TLAAs also may be useful in identifying calculations that 

11 did not meet the six criteria below. 

12 1. Involve systems, structures, and components within the scope of license renewal, as 

13 delineated in 10 CFR 54.4(a). Chapter 2 of this SRP-SLR provides the reviewer 

14 guidance on the scoping and screening methodology, and on plant-level and various 

15 system-level scoping results. 

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

17 material, change in dimension, change in material properties, loss of toughness, loss of 

18 prestress, settlement, cracking, and loss of dielectric properties. 

19 3. Involve time-limited assumptions defined by the current operating term (e.g., 40 years). 

20 The defined operating term should be explicit in the analysis. Simply asserting that a 

21 component is designed for a service life or plant life is not sufficient. The assertion is 

22 supported by calculations or other analyses that explicitly include a time limit. 

23 4. Were determined to be relevant by the licensee in making a safety determination. 

24 Relevancy is a determination that the applicant makes based on a review of the 

25 information available. A calculation or analysis is relevant if it can be shown to have a 

26 direct bearing on the action taken as a result of the analysis performed. Analyses are 

27 also relevant if they provide the basis for a licensee’s safety determination, and, in the 

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

29 5. Show capability of the system, structure, or component to perform its intended 

30 function(s), as delineated. Involve conclusions or provide the basis for conclusions 

31 related to 10 CFR 54.4(b). Analyses that do not affect the intended functions of systems, 

32 structures, and components (SSCs) are not TLAAs. 

33 6. Are contained or incorporated by reference in the CLB. The CLB includes the technical 

34 specifications as well as design basis information (as defined in 10 CFR 50.2), or 

35 licensee commitments documented in the plant-specific documents contained or 

36 incorporated by reference in the CLB, including but not limited to the FSAR, NRC SERs, 

37 the fire protection plan/hazards analyses, correspondence to and from the NRC, the 

38 quality assurance (QA) plan, and topical reports included as references to the FSAR. 

39 Calculations and analyses that are not contained in the CLB or not incorporated by 

40 reference in the CLB are not TLAAs. If a code of record is in the FSAR for particular 

41 groups of structures or components, reference material includes all calculations called for 

42 by that code of record for those structures and components (SCs). 
4.1-4 

1 TLAAs that need to be addressed are not necessarily those analyses that have been previously 

2 reviewed or approved by the NRC. The following examples illustrate TLAAs that need to be 

3 addressed that were not previously reviewed and approved by the NRC: 

4  The FSAR states that the design complies with a certain national code and standard. A 

5 review of the code and standard reveals that it calls for an analysis or calculation. Some 

6 of these calculations or analysis will be TLAAs. The actual calculation was performed by 

7 the applicant to meet the code and standard. The specific calculation was not 

8 referenced in the FSAR. The NRC had not reviewed the calculation. In response to a 

9 generic letter (GL), a licensee submitted a letter to the NRC committing to perform a 

10 TLAA that would address the concern in the GL. The NRC had not documented a 

11 review of the applicant’s response and had not reviewed the actual analysis. 

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

13 under 10 CFR 54.21(c): 

14  Population projections (Section 2.1.3 of NUREG–0800) (Ref. 2). 

15  Cost-benefit analyses for plant modifications. 

16  Analysis with time-limited assumptions defined short of the current operating term of the 

17 plant, for example, an analysis for a component based on a service life that would not 

18 reach the end of the current operating term. 

19 The number and type of TLAAs vary depending on the plant-specific CLB. All six criteria set 

20 forth in 10 CFR 54.3 (and repeated in Subsection 4.1.2) must be satisfied to conclude that a 

21 calculation or analysis is a TLAA. Table 4.1-1 provides examples of how these six criteria may 

22 be applied (Ref. 1). Table 4.1-2 provides a list of generic TLAAs that are included in the 

23 SRP-SLR. Table 4.7-1 in SRP-SLR Section 4.7 provides examples of potential plant-specific 

24 TLAAs that have been identified by license renewal applicants (LRA). It is not expected that all 

25 applicants would identify all the analyses in these tables as TLAAs for their plants. Also, an 

26 applicant may perform specific TLAAs for its plant that are not shown in these tables. 

27 Criterion 3 for TLAAs in 10 CFR 54.3(a) establishes that, as one of the six criteria that are used 

28 to define a given analysis as a TLAA, the analysis has to involve time-limited assumptions 

29 defined by the current operating term (e.g., 40 years). Therefore, for proposed SLR 

30 applications, there may be instances where an existing, time-dependent analysis did not 

31 conform to Criterion 3 for TLAAs in 10 CFR 54.3(a) for the current period of extended operation, 

32 but would conform to this criterion for the subsequent period of extended operation that is 

33 requested for NRC approval. Therefore, the reviewer should perform a review of the CLB to 

34 determine whether there are any existing analyses for the CLB that will need to be identified as 

35 analyses that conform to Criterion 3 for TLAAs for the proposed subsequent period of extended 

36 operation even though the analyses did not conform to Criterion 3 for TLAAs for the previous 

37 period of extended operation that was approved in the renewed operating license for that 

38 period. For those cases where the addition of a proposed subsequent period of extended 

39 operation would cause a given analysis to conform to Criterion 3 for TLAAs in 10 CFR 54.3(a), 

40 the reviewer should assess whether the analysis also conforms to the remaining five criteria for 

41 identifying TLAAs in 10 CFR 54.3(a), and determine whether the analysis needs to be identified 

42 as a TLAA for the subsequent period of extended operation in accordance with the requirement 

43 in 10 CFR 54.21(c)(1). 
4.1-5 

1 As appropriate, NRC staff from other branches of the Office of Nuclear Reactor Regulation 

2 (NRR) review the application in their assigned areas without examining the identification of 

3 TLAAs. However, they may come across situations in which they may question why the 

4 applicant did not identify certain analyses as TLAAs. The reviewer coordinates the resolution of 

5 any such questions with these other NRC staff to determine whether these analyses should be 

6 evaluated as TLAAs. 

7 In order to determine whether there is reasonable assurance that the applicant has identified the 

8 TLAAs for its plant, the reviewer should find that the analyses omitted from the applicant’s list are 

9 not TLAAs. Should an applicant identify a TLAA that is also a basis for a plant-specific 

10 exemption that was granted pursuant to 10 CFR 50.12 and the exemption is in effect for the 

11 current operating period, the reviewer verifies that the applicant also has identified that 

12 exemption pursuant to 10 CFR 54.21(c)(2). Examples of an exemptions that may have been 

13 granted in accordance with 10 CFR 50.12 and based on a TLAA are those NRC-granted 

14 exemptions that approved American Society of Mechanical Engineers (ASME) Code N-514 as 

15 an alternative basis for complying with the pressure lift and system enable temperature setpoint 

16 requirements for PWR low temperature overpressure protection systems in 10 CFR Part 50, 

17 Appendix G and the ASME Code Section XI, Appendix G. 

18 4.1.4 Evaluation Findings 

19 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

20 provisions of this section, and whether the NRC staff’s evaluation supports conclusions of the 

21 following type, to be included in the SER: 

22 On the basis of its review, as discussed above, the NRC staff concludes that the 

23 applicant has provided an acceptable list of TLAAs as defined in 10 CFR 54.3, 

24 and that no 10 CFR 50.12 exemptions have been granted on the basis of a 

25 TLAA, as defined in 10 CFR 54.3. 

26 4.1.5 Implementation 

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

28 the method described herein are used by the NRC staff to evaluate conformance with 

29 NRC regulations. 

30 4.1.6 References 

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

32 10 CFR Part 54–The License Renewal Rule.” Revision 6. Washington, DC: Nuclear 

33 Energy Institute. 1995. 

34 2. NRC. NUREG–0800, “Standard Review Plan for the Review of Safety Analysis Reports 

35 Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

36 March 2007. 

37 3. NRC. “Nuclear Power Plant License Renewal; Revisions.” Federal Register: Vol. 60. 

38 No. 88, pp. 22,461–22,495. May 8, 1995
4.1-6 

Table 4.1-1. Sample Process for Identifying Potential Time-Limited Aging Analyses (TLAA) and Basis for DispositionExample of an analysis that meets all six of the criteria in 10 CFR 54.3(a) for defining an analysis as a TLAA: The current licensing basis 

(CLB) includes a time-dependent fatigue flaw growth analysis for the reactor coolant pump (RCP) flywheels. An age-related fatigue failure of flywheels could potentially be a source of missiles that have the potential to impact the structural integrity and pressure retaining function of the 

reactor coolant pressure boundary. The applicant has identified that the RCP flywheels are components that meet the scoping definition in Title 10 of the Code of Federal Regulations (10 CFR) 54.4(a)(1), in that the flywheels assure adequate heat removal during a plant trip and loss of 

power to the RCPs, as well as initiation of natural circulation flow as part of necessary safe shutdown activities. The applicant has not included the RCP flywheels are components that need to be within the scope of an aging management review (AMR), as would otherwise be required in accordance with 10 CFR 54.21(a)(1). The analysis is referenced in the updated final safety analysis report UFSAR 

and is based on design basis transients that are assumed and evaluated in the UFSAR based on a 40-year design life. The analysis is relied 

upon to establish a 10-year augmented inservice inspection interval for performing inspections of RCP flywheels and to demonstrate that fatigueinduced growth of a flaw in the flywheels would not result in a flywheel missile that could threaten the structure integrity of the reactor coolant pressure boundary during the life of the plant.

Criterion in 10 CFR 54.3(a) Disposition Basis for Comparing to the Criterion in 10 CFR 54.3(a) 

Criterion 1: The analysis must involve systems, structures, and components within the scope of license renewal, as delineated in 10 CFR 54.4(a).

Although the RCP flywheels are active components and do not need to be subjected to an AMR (as defined in 

10 CFR 54.21(a)(1)), the components are within the scope of license renewal application because their failure could impact the intended pressure retaining function of a component that is located in the reactor coolant pressure 

boundary (RCPB). Therefore, the fatigue flaw growth analysis does conform to Criterion 1 in 10 CFR 54.3(a) because the flywheels do need to be within the scope of license renewal as a component whose failure could impact the intended function of a component that has been scoped in for renewal in accordance with 10 CFR 54.4(a)(1). 

Criterion 2: The analysis must consider the effects of aging.

The fatigue flaw growth analysis for the RCP flywheels does meet Criterion 2 because the analysis assumes the presence of a postulated crack in the components and assumes that an age-related growth mechanism (fatigue flaw growth) will grow the flaw under the assumed transient loading conditions for the analysis. 

Criterion 3: The analysis must involve time-limited assumptions defined by the current operating term (for example, 40 years).

The fatigue flaw growth analysis for the RCP flywheels does meet Criterion 3 because the analysis assumes that 

the loading conditions that induced fatigue flaw growth in the flywheel discs are based on the 40-year cyclic transient assumptions for specific design transients in the UFSAR. The 40-year cyclical nature of this assumption defines this analysis as one that involves time-limited assumptions defined by the current operating term. 

Criterion 4: The analysis must be determined to be relevant by the licensee in making a safety determination.

The analysis conforms to Criterion 4 because the applicant is relying on the fatigue flaw growth analysis to establish 

a safety-related decision at the facility, which amounts to the applicant’s safety decision to perform augmented inservice inspection of the RCP flywheels on a 10-year inservice inspection interval and relates to the applicant’s 

basis for maintaining the integrity of the reactor coolant pressure boundary during the life of the plant. 
4.1-7 

Table 4.1-1. Sample Process for Identifying Potential Time-Limited Aging Analyses (TLAA) and Basis for DispositionCriterion 5: The analysis must involve conclusions or provide the basis for conclusions related to the capability of the system, structure, or component to perform its intended function(s), as delineated in 10 CFR 54.4(b).

The analysis conforms to Criterion 5 because the analysis evaluates the structural integrity of the RCP flywheels for 

fatigue-induced growth to ensure the integrity of the flywheels will be maintained during the licensed period of operation for the facility and that the integrity of the reactor coolant pressure boundary will be protected against the 

consequences of postulated flywheel missiles during the life of the plant. 

Criterion 6: The analysis is contained or incorporated by reference in the CLB.

The analysis conforms to Criterion 6 because the analysis is referenced in the UFSAR for the facility. 

Example of analyses that do not meet the six of the criteria for TLAAs in 10 CFR 54.3(a):Example of an analysis that does not meet Criterion 1 in 10 CFR 54.3(a): The analysis must involve systems, structures, and components within the scope of license renewal, as delineated in 10 CFR 54.4(a).

The CLB includes a time-dependent corrosion analysis for both a refueling water storage tank (RWST) and a standby 

RWST that is included in the plant design. The applicant can align the standby RWST to the safety injection system 

and containment spray system for the facility during a postulated loss of coolant accident and the applicant has 

performed a 40-year time-dependent corrosion analysis of both the RWST and standby RWST. The RWST is credited as a safety-related component that is credited for accident mitigation objectives in the plant’s accident 

analyses that are defined and evaluated in the UFSAR. In contrast, the standby RWST is not credited for accident mitigation in the accident analyses defined in the UFSAR. A postulated failure of the standby RWST does not have the ability to impact the intended function [as defined in 10 CFR 54.4(b)] of any safety-related component or structure 

that is required to be scoped in for renewal in accordance with 10 CFR 54.4(a)(1); nor is the standby RWST within the scope of any special regulations, as defined in 

10 CFR 54.4(a)(3). The applicant has not identified the standby RWST as a tank that is within the scope of license renewal. Although the corrosion analysis for the standby RWST is part of the plant design, the analysis does not apply to a 

plant component that is within the scope of the SLRA because the component is not required to be within the scope 

of the license renewal application in accordance with 10 CFR 54.4 (a)(1), (a)(2), or (a)(3). Therefore, under this 

example, the corrosion analysis for the standby RWST does meet Criterion 1 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 

Example of an analysis that does not meet Criterion 2 in 10 CFR 54.3(a): The analysis must consider the effects of aging.

The CLB and design basis includes a stress analysis for a reactor coolant loop elbow that is compared to American 

Society of Mechanical Engineers (ASME) Code Section III allowable stress values. The stress analysis is performed 

in accordance with ASME Section III requirements, as invoked by 10 CFR 50.55a requirements. 

Although the stress analysis is required by the U.S. Nuclear Regulatory Commission (NRC) regulations and ASME 

Code requirements and is part of the CLB, it does not involve any analysis of an applicable or postulated aging effect. 

Therefore, under this example, the analysis does not conform to Criterion 2 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 
4.1-8 

Table 4.1-1. Sample Process for Identifying Potential Time-Limited Aging Analyses (TLAA) and Basis for DispositionExample of an analysis that does not meet Criterion 3 in 10 CFR 54.3(a): The analysis must involve time-limited assumptions defined by the current operating term (for example, 40 years).

The applicant has detected a flaw in one of its reactor vessel nozzle-to-safe end welds and has performed an ASME Code Section XI inservice inspection flaw growth analysis of the flaw in the components to justify further service of 

the impacted weld until the next outage in which the flaw would be inspected for acceptability, without the need of 

repair or replacement. The ASME-based flaw evaluation is part of the CLB and assumes the Class 1 design basis transients occur over a 20-year period from the time the flaw was detected. The analysis does not involve time-dependent assumptions defined by the current operating period because the assessment of design basis transient cycles was made on a time period less than that used for the current operating 

term. Therefore, under this example, the fatigue flaw analysis would not conform to Criterion 3 in 10 CFR 54.3(a) and would not meet the definition of a TLAA in the 10 CFR Part 54 rule. 

Example of an analysis that does not meet Criterion 4 in 10 CFR 54.3(a): The analysis must be determined to be relevant by the licensee in making a safety determination.

The original licensing basis for a pressurized water reactor (PWR) included a high-energy line break (HELB) analysis for a piping location in the main reactor coolant loop that was based on ASME Section III cumulative usage factor 

(CUF) analysis requirements for high energy line break locations and demonstrated the need for inclusion of a pipe whip restraint in the design of the piping location. Subsequent to the performance of this analysis, the applicant 

submitted a leak-before-break (LBB) analysis for the main coolant loop piping that demonstrated conformance with the revised dynamic effect requirements in NRC General Design Criterion 4. The results of the LBB analysis 

demonstrated that the licensee would be capable of detecting a leak in the affected piping prior to a catastrophic failure of the component and that the pipe whip restraints could be removed from the design of the component. The LBB analysis was approved as part of an update of the CLB for the facility such that the HELB analysis is no longer relied upon as part of the CLB for this piping location. The original HELB analysis for this piping location is no longer relied upon for the CLB because it was replaced by the NRC-approved LBB analysis for the main coolant loops, which included these piping locations. Therefore, the original HELB analysis for this piping location is not relevant in making a safety determination relative to the inclusion 

of a pipe whip restraint on the piping component. Under this example, the HELB analysis for this specific piping 

location does not conform to Criterion 4 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR 

Part 54 rule. HELB analyses for piping locations not excluded by LBB would still be relied upon for the CLB and 

would need to be identified as TLAAs for the LRA. 

Example of an analysis that does not meet Criterion 5 in 10 CFR 54.3(a): The analysis must involve conclusions or provide the basis for conclusions related to the capability of the system, structure, or component to perform its intended function(s), as 

The original licensing basis for a BWR included an evaluation of the number of paint coats that would be applied to the inside surfaces of its condensate storage tanks (CSTs). The CSTs have been included in the scope of the license renewal application in accordance with 10 CFR 54.4(a)(1) requirements and are within the scope of an 

applicable AMR, as performed in accordance with 10 CFR 54.21(a)(1) requirements. Although the coating analysis 

for the inside surfaces of the CST is discussed in the UFSAR, the UFSAR states that the analysis is not relied upon for the structural integrity of the CST or for drawing a conclusion that the CST will fulfill its accident mitigation and safe shutdown functions. Although the coating analysis is part of the design basis, it is not used to draw a conclusion or provide the basis for concluding that the structural integrity of the CST walls will be maintained during the design life of the plant or the ability of the CST coolant inventory to meet the accident mitigation or safe shutdown objectives for the plant design. 
4.1-9 

Table 4.1-1. Sample Process for Identifying Potential Time-Limited Aging Analyses (TLAA) and Basis for Dispositiondelineated in 10 CFR 54.4(b).

Therefore, the coating analysis for the CST does not involve conclusions or provide the basis for conclusions related to the capability of the CST to perform its intended functions, as defined in 10 CFR 54.4(b). Under this example, the coating analysis for the CST does not conform to Criterion 5 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 

Example of an analysis that does not meet Criterion 6 in 10 CFR 54.3(a): The analysis is contained or incorporated by reference in the CLB.

The CLB for a PWR includes a plant-specific, probabilistic main turbine missile analysis that is used as basis for 

meeting 10 CFR Part 50, Appendix A, dynamic effect analysis design requirements, as given in General Design Criterion 4, “Dynamic Effects.” This analysis is described and evaluated in the UFSAR, and states that the analysis 

was performed to demonstrate the main turbines will not generate a missile that could threaten the integrity of safetyrelated structures and components in the facility. The UFSAR indicates that the probabilistic turbine missile analysis 

was performed in lieu of a generic time-dependent turbine missile analysis that is provided in a specific vendor report and that meets all six of the criteria for defining TLAAs in 10 CFR 54.3(a). In this case, although the generic time dependent turbine missile analysis in the vendor report could have been relied upon for the CLB, the applicant does not rely on the analysis in this report as its basis for meeting General Design Criterion 4 requirements in 10 CFR Part 50, Appendix A. Therefore, the generic analysis in the vendor report is not contained or incorporated by reference in the CLB. Under this example, the generic turbine missile analysis in the vendor report does not conform to Criterion 6 in 10 CFR 54.3(a) and does not meet the definition of a TLAA in the 10 CFR Part 54 rule. 
4.1-10 

Table 4.1-2. Generic Time-Limited Aging Analyses 

Reactor Vessel Neutron 

Embrittlement (Subsection 4.2) 

Neutron Fluence 

Pressurized Thermal Shock (PWRs Only) 

Upper Shelf Energy (PWRs and BWRs) 

Pressure Temperature (P-T) Limits (PWRs and BWRs) 

Low Temperature Overpressure Protection System 

Setpoints (PWRs Only) 

Ductility Reduction Evaluation for Reactor Internals 

(B&W designed PWRs only) 

RPV Circumferential Weld Relief–Probability of Failure 

and Mean Adjusted Reference Temperature Analysis 

for the RPV Circumferential Welds (BWRs only) 

Reactor Vessel Axial Weld Probability of Failure and 

Mean Adjusted Reference Temperature Analysis 

(BWRs only) 

Metal Fatigue (Subsection 4.3) Metal Fatigue of Class 1 Components 

Metal Fatigue of Non-Class 1 Components 

Environmentally-Assisted Fatigue 

High Energy Line Break Analyses 

Cycle-dependent Fracture Mechanics or Flaw 

Evaluations 

Cycle-dependent Fatigue Waivers 

Environmental Qualification of Electrical Equipment (Subsection 4.4) 

Concrete Containment Tendon Prestress (Subsection 4.5) 

Containment Liner Plate, Metal Containments, and Penetrations Fatigue (Subsection 4.6) 
4.2-1 

1 4.2 Reactor Pressure Vessel Neutron Embrittlement Analysis 

2 Review Responsibilities 

3 Primary—Branch responsible for the time-limited aging analysis (TLAA) issues 

4 Secondary—Branch responsible for reactor systems 

5 4.2.1 Areas of Review 

6 During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in the 

7 reactor pressure vessel (RPV) beltline region of light-water nuclear power reactors, where RPV 

8 beltline region is described in Regulatory Issue Summary (RIS) 2014-11. Areas of review to 

9 ensure that the RPV has adequate fracture toughness to prevent brittle failure during normal 

10 and off-normal operating conditions are (a) upper-shelf energy, (b) pressurized thermal shock 

11 (PTS) for pressurized water reactor (PWRs), (c) heat-up and cool-down (pressure-temperature 

12 limits) curves, (d) BWRVIP-05 analysis for elimination of circumferential weld inspection and 

13 analysis of the axial welds, and (e) other plant-specific TLAAs on RPV neutron embrittlement. 

14 The adequacy of the analyses for these five areas is reviewed for the subsequent period of 

15 extended operation. 

16 The branch responsible for reactor systems reviews neutron fluence and dosimetry information 

17 in the application. 

18 4.2.2 Acceptance Criteria 

19 The acceptance criteria for the areas of review described in Subsection 4.2.1 of this review plan 

20 section delineate acceptable methods for meeting the requirements of the U.S. Nuclear 

21 Regulatory Commission (NRC) regulation in Title 10 of the Code of Federal Regulations

(10 CFR) 54.21(c)(1) (Refs. 2, 3).1 22 

23 4.2.2.1 Time-Limited Aging Analysis 

24 Pursuant to 10 CFR 54.21(c)(1)(i)–(iii), an applicant must demonstrate one of the following: 

25 (i) The analyses remain valid for the period of extended operation; 

26 (ii) The analyses have been projected to the end of the period of extended operation; or 

27 (iii) The effects of aging on the intended function(s) will be adequately managed for the 

28 period of extended operation. 

29 For the first three areas of review for the analysis of RPV neutron embrittlement, the specific 

30 acceptance criteria depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii).

 

1

For subsequent license renewal applications, the period of extended operation concerns the period of operation after 

the expiration of the renewed license (i.e., operation from 60 to 80 years). 
4.2-2 

1 4.2.2.1.1 Neutron Fluence 

2 Neutron fluence is the number of neutrons accumulated per unit area during a certain period 

3 of neutron irradiation. A RPV neutron fluence analysis involves time-limited assumptions 

4 (e.g., 40 years of original design life) and is used to determine the loss of fracture toughness 

5 due to neutron irradiation embrittlement of the RPV. Appendix H to 10 CFR Part 50 (Ref. 4) 

6 requires that an applicant must implement a RPV Surveillance program for a RPV if the peak 

neutron fluence at the end of the design life of the RPV exceeds a neutron fluence of 1017 n/cm2 7 

8 [E > 1 MeV]. The RPV neutron fluence analysis is also integral to other neutron embrittlement 

9 TLAAs [e.g., upper shelf energy and pressure-temperature (P-T) limits analyses] because 

10 neutron fluence is a fundamental parameter which is used to determine the level of neutron 

11 irradiation embrittlement of a RPV. As discussed above, the RPV neutron fluence analysis is 

12 important in making a safety determination for a RPV in terms of loss of fracture toughness due 

13 to neutron irradiation embrittlement. 

14 Typically, the RPV neutron fluence analysis is described in the applicant’s Final Safety Analysis 

15 Report (FSAR) or other design documents approved by NRC. In its subsequent license renewal 

16 application (SLRA), the applicant identifies (a) the neutron fluence for each beltline material at 

17 the end of extended license term, (b) the NRC staff-approved methodology used to calculate the 

18 neutron fluence or submits the methodology for NRC staff review, (c) whether the methodology 

19 is consistent with the guidance in NRC Regulatory Guide (RG) 1.190 (Ref. 5), and (d) how the 

20 neutron fluence is monitored during the subsequent period of extended operation. An applicant 

21 may take any one of the following three dispositions for the RPV neutron fluence analysis. 

22 4.2.2.1.1.1 10 CFR 54.21(c)(1)(i) 

23 A neutron fluence analysis typically accounts for planned operation by including assumptions 

24 regarding the neutron flux emitted from the core. The flux is integrated over time to yield the 

25 estimated fluence. Frequently, neutron fluence calculations will include projected fluence values 

26 for multiple periods of exposure, (e.g., 40, 60, and 80 calendar years). In order to use a 

27 disposition for fluence pursuant to 10 CFR 54.21(c)(1)(i), the applicant will demonstrate the 

28 existing RPV neutron fluence analysis, including the projected flux for planned operation, in the 

29 current licensing basis (CLB) remains valid during the subsequent period of extended operation. 

30 The fluence calculation will be re-evaluated to confirm its validity. 

31 4.2.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

32 For a disposition in accordance with 10 CFR 54.21(c)(1)(ii), the applicant will provide new or 

33 updated calculations that address the fluence effects during the subsequent period of extended 

34 operation. The new or updated RPV neutron fluence analysis is evaluated to consider the 

35 subsequent period of extended operation in accordance with (1) NRC RG 1.190, or (2) a 

36 methodology that has been approved for use by the NRC. 

37 4.2.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

38 In the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report 

39 AMP X.M2, “Neutron Fluence Monitoring,” the NRC staff has evaluated an aging management 

40 program (AMP) for projecting and monitoring neutron fluence for the subsequent period of 

41 extended operation. The staff has determined that this program is acceptable to project and 

42 monitor neutron fluence for managing loss of fracture toughness due to neutron irradiation 

43 embrittlement of RPVs in accordance with 10 CFR 54.21(c)(1)(iii). 
4.2-3 

1 4.2.2.1.2 Upper-Shelf Energy 

2 10 CFR Part 50 Appendix G (Ref. 6) paragraph IV.A.1 requires that the RPV beltline materials 

3 have a Charpy upper-shelf energy (USE) of no less than 68 J [50 ft-lb] throughout the life of the 

4 RPV, unless otherwise approved by the NRC. An applicant may take any one of the following 

5 three approaches. 

6 4.2.2.1.2.1 10 CFR 54.21(c)(1)(i) 

7 The RPV components evaluated in the existing USE analysis or NRC-approved equivalent 

8 margins analysis (EMA) are reevaluated to demonstrate that the existing analysis remains valid 

9 during the subsequent period of extended operation because the neutron fluence projected to 

10 the end of the subsequent period of extended operation is bounded by the neutron fluence in 

11 the existing NRC-approved USE or EMA analysis. 

12 4.2.2.1.2.2 10 CFR 54.21(c)(1)(ii) 

13 The RPV components evaluated in the existing USE analysis or NRC-approved EMA are 

14 reevaluated to consider the subsequent period of extended operation in accordance with 

15 10 CFR Part 50, Appendix G. 

16 10 CFR Part 50, Appendix G, Section IV.A.1 (the rule) requires applicants to take further 

17 corrective actions where the 50 ft-lbs [68 joules] end-of-life (EOL) USE criterion cannot be met. 

18 When this occurs, the rule requires a licensee to submit a supplemental analysis for NRC 

19 approval. The applicant will need to submit a plant-specific engineering analysis (usually an 

20 EMA) for NRC approval as supplemental information for subsequent license renewal (SLR). 

21 Otherwise, failure to meet the USE requirements of 10 CFR Part 50, Appendix G for the RPV 

22 materials as evaluated using the neutron fluence that are projected for the subsequent period of 

23 extended operation mandates imposition of additional commitments or license conditions on 

24 USE for the SLRA. 

25 4.2.2.1.2.3 10 CFR 54.21(c)(1)(iii) 

26 Acceptance criteria for accepting USE TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) have 

27 yet to be developed. They will be evaluated on a case-by-case basis to ensure that the aging 

28 effects will be managed such that the intended function(s) will be maintained during the 

29 subsequent period of extended operation. 

30 4.2.2.1.3 Pressurized Thermal Shock (for PWRs) 

31 For PWRs, 10 CFR 50.61 (Ref. 7) requires that the reference temperature for RPV beltline 

32 materials evaluated at the neutron fluence corresponding to the end of the subsequent period of 

33 extended operation, reference temperature pressurized thermal shock (RTPTS), be less than the 

34 PTS screening criteria at the expiration date of the operating license, unless otherwise approved 

35 by the NRC. The PTS screening criteria are 132 °C [270 °F] for plates, forgings, and axial weld 

36 materials, and 149 °C [300 °F] for circumferential weld materials. Alternatively, the licensee 

37 may comply with the requirements of 10 CFR 50.61a (Ref. 8). The regulations require updating 

38 of the PTS assessment upon a request for a change in the expiration date of a facility’s 

39 operating license, or whenever there is a significant change in projected values of RTPTS. 

40 Therefore, the RTPTS value must be calculated for the entire licensed operating period of the 

41 facility, including the subsequent period of extended operation. If the analyses result in RTPTS
4.2-4 

1 values that exceed the PTS screening criteria at the end of the subsequent period of extended 

2 operation, the applicant is required to implement additional corrective actions as described in 

3 10 CFR Part 50.61 or 10 CFR 50.61a. The PTS TLAA may be handled as follows. 

4 4.2.2.1.3.1 10 CFR 54.21(c)(1)(i) 

5 The existing PTS analysis based on 10 CFR 50.61 remains valid during the subsequent period 

6 of extended operation because the neutron fluence projected to the end of the subsequent 

7 period of extended operation is bound by the neutron fluence assumed in the existing analysis. 

8 If the existing PTS analysis is based on 10 CFR 50.61a, the applicant demonstrates that the 

9 current analysis remains applicable for the subsequent period of extended operation. 

10 4.2.2.1.3.2 10 CFR 54.21(c)(1)(ii) 

11 The PTS analysis is reevaluated to consider the subsequent period of extended operation in 

12 accordance with 10 CFR 50.61 or 10 CFR 50.61a. If the analyses result in RTPTS values that 

13 exceed the PTS screening criteria at the end of the subsequent period of extended operation, 

14 the applicant is required to implement additional corrective actions as described in 

15 10 CFR Part 50.61 or 10 CFR 50.61a. If the existing PTS analysis is based on 10 CFR 50.61a, 

16 the applicant updates the submittal to reflect the subsequent period of extended operation. 

17 4.2.2.1.3.3 10 CFR 54.21(c)(1)(iii) 

18 The NRC staff position for license renewal (LR) on this option is described in a May 27, 2004 

19 letter from L.A. Reyes (EDO) to the Commission (Ref. 9), which states that if the applicant does 

20 not extend the TLAA, the applicant provides an assessment of the CLB TLAA for PTS, a 

21 discussion of the flux reduction program implemented in accordance with 10 CFR 50.61(b)(3), if 

22 necessary, and an identification of the viable options that exist for managing the aging effect in 

23 the future. 

24 4.2.2.1.4 Pressure-Temperature Limits 

25 10 CFR Part 50, Appendix G (Ref. 4) requires that the RPV be maintained within established 

26 P-T limits during normal operating conditions of the plant (including heatups and cooldowns of 

27 the reactor and anticipated operational transients), and during pressure tests and system leak 

28 tests. These limits specify the maximum allowable pressure as a function of reactor coolant 

29 temperature. As the RPV becomes embrittled and its fracture toughness is reduced, the 

30 allowable pressure (given the required minimum temperature) is reduced. Regulatory Issue 

31 Summary (RIS) 2014-11 clarifies issues that must be addressed in developing P-T limits 

32 (Ref. 1). 

33 P-T limits are TLAAs for the application if the plant currently has P-T limit curves approved for 

34 the expiration of the current period of operation [i.e., 54 effective full power year (EFPY) or 

35 some other licensed EFPY value defined for the expiration date of the current license]. 

36 However, the P-T limits for the subsequent period of extended operation need not be submitted 

37 as part of the SLRA since the P-T limits need to be updated through the 10 CFR 50.90 licensing 

38 process when necessary for P-T limits that are located in the limiting conditions of operations 

39 (LCOs) of the Technical Specifications (TS). For those plants that have approved pressure40 temperature limit reports (PTLRs), the P-T limits for the subsequent period of extended 

41 operation will be updated at the appropriate time through the plant’s Administrative Section of 

42 the TS and the plant’s PTLR process. In either case, the 10 CFR 50.90 or the PTLR processes, 
4.2-5 

1 which constitute the CLB, will ensure that the P-T limits for the subsequent period of extended 

2 operation will be updated prior to expiration of the P-T limit curves for the current period 

3 of operation. 

4 P-T limits may be handled as follows. 

5 4.2.2.1.4.1 10 CFR 54.21(c)(1)(i) 

6 The applicant demonstrates (on a case-by-case basis) that existing P-T limits in the CLB will 

7 remain valid during the subsequent period of extended operation. 

8 4.2.2.1.4.2 10 CFR 54.21(c)(1)(ii) 

9 The P-T limits are updated for the subsequent period of extended operation in accordance with 

10 10 CFR Part 50, Appendix G (Ref. 4) and the applicant’s appropriate TS change process for 

11 updating the P-T limit curves. 

12 For P-T limit curves that are included in and controlled by requirements in the limiting conditions 

13 of operations of the plant TS, the applicant submits the changes to the P-T limits as a license 

14 amendment request (i.e., a TS change request) for the LRA that is submitted in accordance with 

15 the requirements 10 CFR 54.22 and uses the license amendment submittal as the basis for 

16 accepting the TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

17 For P-T limits that are controlled by Administrative Controls TS requirements and located in an 

18 NRC-approved PTLR, the applicant updates the P-T limits in accordance with the methodology 

19 or methodologies approved in the applicable Administrative Controls TS section for its PTLR 

20 process and submits the updated PTLR(s) containing the updated P-T limits to the NRC 

21 (as information) in accordance the reporting requirements in the applicable Administrative 

22 Controls TS section. The applicant uses the submittal of the updated PTLR as the basis for 

23 accepting the TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

24 4.2.2.1.4.3 10 CFR 54.21(c)(1)(iii) 

25 Updated P-T limits for the subsequent period of extended operation must be established and 

26 completed using the applicable TS change process for updating the P-T limit curves prior to the 

27 plant’s entry into the subsequent period of extended operation. The 10 CFR 50.90 (Ref. 10) 

28 process for P-T limits located in the LCOs or the Administrative Controls Process for P-T limits 

29 that are administratively amended through a PTLR process can be considered adequate AMPs 

30 or aging management activities within the scope of 10 CFR 54.21(c)(1)(iii), such that P-T limits 

31 will be maintained through the subsequent period of extended operation. 

32 4.2.2.1.5 Elimination of Boiling Water Reactor Circumferential Weld Inspections 

33 Some boiling water reactors (BWRs) have an approved technical alternative, which eliminates 

34 the RPV circumferential shell weld inspections from the Section XI program for the current 

35 license term. Approved technical alternatives for SLR have yet to be developed. They will be 

36 evaluated on a case-by-case basis to ensure that the aging effects will be managed in 

37 accordance with 10 CFR 54.21(c)(1) such that the intended function(s) will be maintained during 

38 the subsequent period of extended operation. 
4.2-6 

1 4.2.2.1.6 BWR Axial Welds 

2 Those BWRs that have been approved to use the circumferential weld technical alternative also 

3 had to justify acceptable conditional probability of failure for their RPV axial shell weld 

4 examination coverage from the Section XI program for the current license term. Approved 

5 technical alternatives for SLR have yet to be developed. They will be evaluated on a 

6 case-by-case basis to ensure that the aging effects will be managed in accordance with 

7 10 CFR 54.21(c)(1) such that the intended function(s) will be maintained during the subsequent 

8 period of extended operation. 

9 4.2.2.2 Final Safety Analysis Report Supplement 

10 The specific criterion for meeting 10 CFR 54.21(d) is that the summary description of the 

11 evaluation of TLAAs for the subsequent period of operation in the FSAR supplement is 

12 appropriate, such that later changes can be controlled by 10 CFR 50.59 (Ref. 11). The 

13 description contains information associated with the TLAAs regarding the basis for 

14 determining that the applicant has made the demonstration required by 

15 10 CFR 54.21(c)(1). 

16 4.2.3 Review Procedures 

17 For each area of review described in Subsection 4.2.1, the following review procedures should 

18 be followed. 

19 4.2.3.1 Time-Limited Aging Analysis 

20 For the first four areas of review for the analysis of RPV neutron embrittlement, the review 

21 procedures depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). For each 

22 area, the applicant’s three options under section 54.21(c)(1) are discussed in turn. 

23 The applicant may identify activities to be performed to verify the assumption basis of the 

24 neutron fluence calculations that are used to evaluate the RPV neutron embrittlement analyses. 

25 An evaluation of that verification activity is provided by the applicant in the SLRA. The reviewer 

26 assures that the applicant’s verification activity is sufficient to confirm the calculation 

27 assumptions for the 80-year period. If the assumption basis is not verified, the applicant must 

28 reevaluate the analysis and take appropriate corrective actions as necessary, consistent with 

29 the requirements of the affected regulation. 

30 4.2.3.1.1 Neutron Fluence 

31 4.2.3.1.1.1 10 CFR 54.21(c)(1)(i) 

32 The reviewer confirms that the applicant’s existing RPV neutron fluence analysis remains valid 

33 during the subsequent period of extended operation. The reviewer also confirms that the 

34 applicant identifies (a) the neutron fluence for each beltline material at the end of the 

35 subsequent period of extended operation, (b) the NRC staff-approved methodology used to 

36 determine the neutron fluence or submits the methodology for NRC staff review, and 

37 (c) whether the methodology is consistent with the guidance in NRC RG 1.190.(Ref. 5).
4.2-7 

1 4.2.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

2 The reviewer confirms that the applicant adequately reevaluated its RPV neutron fluence 

3 analysis for the subsequent period of extended operation. As part of its review, the review 

4 confirms that the applicant identifies (a) the neutron fluence for each beltline material at the end 

5 of the subsequent period of extended operation, (b) the NRC staff-approved methodology used 

6 to determine the neutron fluence or submits the methodology for NRC staff review, and 

7 (c) whether the methodology is consistent with the guidance in NRC RG 1.190. 

8 4.2.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

9 GALL-SLR Report AMP X.M2, “Neutron Fluence Monitoring” of the GALL-SLR Report provides 

10 an acceptable method to project and monitor RPV neutron fluence through the subsequent 

11 period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii). The NRC staff reviews 

12 an applicant’s program for dispositioning the TLAA in accordance with the requirements in 

13 10 CFR 54.21(c)(1)(iii) and the guidance in GALL-SLR Report AMP X.M2. Plant-specific 

14 approaches to projecting and monitoring neutron fluence will be evaluated on a case-by-case 

15 basis to ensure that the aging effects due to neutron irradiation embrittlement will be managed 

16 such that the intended functions(s) will be adequately maintained for the subsequent period of 

17 extended operation. 

18 4.2.3.1.2 Upper-Shelf Energy 

19 4.2.3.1.2.1 10 CFR 54.21(c)(1)(i) 

20 The projected 1⁄4T neutron fluence at the end of the subsequent period of extended operation is 

21 reviewed for all beltline materials to verify that it is bounded by the neutron fluence assumed in 

22 the existing NRC-approved USE or EMA analysis in the CLB. 

23 4.2.3.1.2.2 10 CFR 54.21(c)(1)(ii) 

24 The documented results of the revised USE analysis (or revised EMA analysis, as applicable) 

25 based on the projected neutron fluence at the end of the subsequent period of extended 

26 operation are reviewed for compliance with 10 CFR Part 50, Appendix G. The applicant may 

27 use NRC RG 1.99 Rev. 2 (Ref. 12) as the basis for using the 1⁄4 T neutron fluence values for the 

28 reactor vessel beltline components (as projected to the end of the SLR period) to project the 

29 USE values for the reactor vessel beltline components at the end of the subsequent period of 

30 extended operation. The applicant also may use ASME Code Section XI Appendix K (Ref. 13) 

31 for the purpose of performing an equivalent margins analysis to demonstrate that adequate 

32 protection for ductile failure is maintained to the end of the subsequent period of extended 

33 operation. The NRC staff reviews the applicant’s methodology for this evaluation. Branch 

34 Technical Position (BTP) MTEB 5-3, “Fracture Toughness Requirements,” in Standard Review 

35 Plan (Ref. 14), Section 5.3.2, “Pressure Temperature Limits, Upper-Shelf Energy, and 

36 Pressurized Thermal Shock,” provides additional NRC positions on estimations of USE values 

37 for RPV beltline materials. 
4.2-8 

1 The NRC staff confirms that the applicant has provided sufficient information for all USE and/or 

2 equivalent margins analysis calculations for the subsequent period of extended operation 

3 as follows: 

4 The applicant identifies the neutron fluence at the 1⁄4T location for each beltline 

5 material at the expiration of the subsequent period of extended operation. 

6 To confirm that the USE analysis meets the requirements of Appendix G of 10 CFR Part 50 

7 (Ref. 6) at the end of the subsequent period of extended operation, the NRC staff 

8 determines whether: 

9 1. For each beltline material, the applicant provides the unirradiated USE and the projected 

10 USE at the end of the subsequent period of extended operation, and whether the drop in 

11 USE was determined using the limit lines in Figure 2 of NRC RG 1.99, Rev 2, based on 

12 the material copper content, or from surveillance data. 

13 2. If an equivalent margins analysis is used to demonstrate compliance with the USE 

14 requirements in Appendix G of 10 CFR Part 50, the applicant provides the analysis or 

15 identifies an NRC-approved topical report that contains the analysis which is applicable 

16 to the subsequent period of extended operation. Information the NRC staff considers to 

17 assess the equivalent margins analysis includes the unirradiated USE (if available) for 

18 the material, its copper content, the neutron fluence (1⁄4T and at 1-inch depth), the 

19 projected SLR USE, the operating temperature in the downcomer at full power, the 

20 vessel radius, the vessel wall thickness, the J-applied analysis for Service Level C and 

21 D, the vessel accumulation pressure, and the vessel bounding heatup/cooldown rate 

22 during normal operation. 

23 4.2.3.1.2.3 10 CFR 54.21(c)(1)(iii) 

24 The applicant’s proposal to demonstrate that the effects of aging on the intended function(s) 

25 will be adequately managed for the subsequent period of extended operation is reviewed on a 

26 case-by-case basis. 

27 4.2.3.1.3 Pressurized Thermal Shock (for PWRs) 

28 4.2.3.1.3.1 10 CFR 54.21(c)(1)(i) 

29 The projected clad-to-base metal interface neutron fluence at the end of the subsequent period 

30 of extended operation is reviewed to verify that it is bounded by the neutron fluence assumed in 

31 the existing PTS analysis. 

32 For PTS analysis based on a NRC-approved submittal based on 10 CFR 50.61a, the applicant 

33 demonstrates that the analysis bounds the subsequent period of extended operation. 

34 4.2.3.1.3.2 10 CFR 54.21(c)(1)(ii) 

35 The documented results of the revised PTS analysis based on the projected neutron fluence at 

36 the end of the subsequent period of extended operation are reviewed for compliance with 

37 10 CFR 50.61or 10 CFR 50.61a. 

38 (Ref. 7, 8) 
4.2-9 

1 The NRC staff confirms that the applicant has provided sufficient information for PTS for the 

2 subsequent period of extended operation as follows: 

3 The applicant identified the neutron fluence at the clad-to-base metal interface for 

4 each beltline material at the expiration of the subsequent period of extended 

5 operation. 

6 There are two methodologies from 10 CFR 50.61 that can be used in the PTS analysis, based 

7 on the projected neutron fluence at the end of the subsequent period of extended operation. 

8 RTNDT is the reference temperature (NDT means nil-ductility temperature) used as an indexing 

9 parameter to determine the fracture toughness and the amount of embrittlement of a material. 

10 RTPTS is the reference temperature used in the PTS analysis and is related to RTNDT at the end 

11 of the facility’s operating license. 

12 The first methodology does not rely on plant-specific surveillance data to calculate delta RTNDT

13 (i.e., the mean value of the adjustment or shift in reference temperature caused by irradiation). 

14 The delta RTNDT is determined by multiplying a chemistry factor from the tables in 10 CFR 50.61 

15 by a neutron fluence factor calculated from the neutron flux using an equation. 

16 The second methodology relies on plant-specific surveillance data to determine the delta RTNDT. 

17 In this methodology, two or more sets of surveillance data are needed. A surveillance datum 

18 consists of a measured delta RTNDT for corresponding neutron fluence. 10 CFR 50.61 specifies 

19 a procedure and a criterion for determining whether the surveillance data are credible. For the 

20 surveillance data to be defined as credible, the difference in the predicted value and the 

21 measured value for delta RTNDT must be less than −2.2 °C [28 °F] for weld metal. When a 

22 credible surveillance data set exists, the chemistry factor can be determined from these data in 

23 lieu of a value from the table in 10 CFR 50.61. Then the standard deviation of the increase in 

24 the RTNDT can be reduced from −2.2 °C [28°F] to −10 °C [14°F] for welds. 

25 To confirm that the PTS analysis results in RTPTS values below the screening criteria in 

26 10 CFR 50.61 at the end of the subsequent period of extended operation, the applicant provides 

27 the following: 

28 1. For each beltline material, provide the unirradiated RTNDT, the method of calculating the 

29 unirradiated RTNDT (either generic or plant-specific), the margin, chemistry factor, the 

30 method of calculating the chemistry factor, the mean value for the shift in transition 

31 temperature, and the RTPTS value. 

32 2. If there are two or more data for a surveillance material that is from the same heat of 

33 material as the beltline material, provide analyses to determine whether the data are 

34 credible in accordance with NRC RG 1.99, Rev 2 (Ref. 12) and whether the margin 

35 value used in the analysis is appropriate. 

36 3. If a surveillance program does not include the vessel beltline controlling material but two 

37 or more data seta are available from other beltline materials, then provide an analysis of 

38 the data in accordance with NRC RG 1.99, Rev 2, Regulatory Position C.2.1, to show 

39 that the results either bound or are comparable to the values that would be calculated for 

40 the same materials using Regulatory Position C.1.1. 

41 If the PTS screening criteria in 10 CFR 50.61 are projected to be exceeded during the 

42 subsequent period of extended operation, an analysis based on NRC RG 1.154 (Ref. 15) or 
4.2-10 

1 10 CFR 50.61a may be submitted for review. For applicants with PTS analysis based upon an 

2 NRC-approved submittal using 10 CFR 50.61a, the analysis is revised to reflect the subsequent 

3 period of extended operation. 

4 4.2.3.1.3.3 10 CFR 54.21(c)(1)(iii) 

5 The NRC staff reviews the applicant’s proposal to demonstrate that the effects of aging on the 

6 intended function(s) will be adequately managed for the subsequent period of extended 

7 operation will be reviewed on a case-by-case basis. 

8 If corrective actions are necessary, the NRC staff ensures that the SLRA provides an 

9 assessment of the CLB TLAA for PTS, a discussion of the flux reduction program implemented 

10 in accordance with §50.61(b)(3), if necessary, and an identification of the viable options that 

11 exist for managing the aging effect in the future. As part of this review, the staff ensures that the 

12 applicant addressed the following topics: 

13 A. The applicant explains its core management plans (e.g., operation with a low leakage 

14 core design and/or integral burnable neutron absorbers) from now through the end of 

15 the subsequent period of extended operation. Based on this core management strategy, 

16 the applicant: 

17 (1) Identifies the material in the RPV which has limiting RTPTS value, 

18 (2) Provides the projected neutron fluence value for the limiting material at end of the 

19 subsequent period of extended operation, 

20 (3) Provides the projected RTPTS value for the limiting material at end of the 

21 subsequent period of extended operation, and 

22 (4) Provides the projected date and neutron fluence values at which the limiting 

23 material will exceed the screening criteria in §50.61. 

24 B. The applicant discusses the AMPs or aging management activities that it intends to 

25 implement, which actively “manage” the condition of the facility’s RPV and hence, the 

26 risk associated with PTS. This discussion is expected to address, at least, the facility’s 

27 reactor pressure vessel material surveillance program. 

28 C. If corrective actions are necessary, the applicant briefly discusses the options that it is 

29 considering with respect to “resolving” the PTS issue through end of the subsequent 

30 period of extended operation. It is anticipated that this discussion includes some or all of 

31 the following: 

32 (1) Plant modifications [e.g., heating of emergency core cooling system (ECCS) 

33 injection water] which could limit the risk associated with postulated PTS events 

34 [see §50.61(b)(4) and/or (b)(6)], 

35 (2) More detailed safety analyses which may be performed to show that the PTS risk 

36 for the facility is acceptably low through end of the subsequent period of 

37 extended operation [see §50.61(b)(4)], 
4.2-11 

1 (3) More advanced material property evaluation (e.g., use of Master Curve 

2 technology) to demonstrate greater fracture resistance for the limiting material 

3 [applies to §50.61(b)(4)], 

4 (4) The potential for RPV thermal annealing in accordance with §50.66 

5 [see §50.61(b)(7)], and/or 

6 (5) Use of the alternative PTS Rule (Ref. 8). 

7 4.2.3.1.4 Pressure-Temperature Limits 

8 The regulation in 10 CFR Part 50, Appendix G (Ref. 6) requires that the RPV be maintained 

9 within established P-T limits during normal operating conditions of the plant, including heatups 

10 and cooldowns of the reactor and anticipated operational transients, and during pressure test 

11 and system leak test conditions. These limits specify the maximum allowable pressure as a 

12 function of reactor coolant temperature. As the RPV becomes embrittled and its fracture 

13 toughness is reduced, the allowable pressure (given the required minimum temperature) 

14 is reduced. 

15 The regulation in 10 CFR 50.36 (Ref. 16) requires that P-T limits be controlled by plant TS; 

16 however, the process for performing updates of the P-T limits depends on whether the P-T limit 

17 curves for the facility are maintained in the Limiting Conditions of Operation Section of the TS 

18 (i.e., in the TS LCOs) or in a PTLR that is controlled and updated in accordance with the 

19 Administrative Controls Section of the plant TS (i.e., by an Administrative Controls TS Section). 

20 P-T limits are TLAAs for the application if the plant currently has P-T limit curves approved for 

21 the expiration of the current period of operation (i.e., 32 EFPY or some other licensed EFPY 

22 value defined for the expiration date of the current license). However, as stated in SRP-SLR 

23 Section 4.2.2.1.3, the assessment of P-T limit TLAAs for incoming LRAs and basis for accepting 

24 the TLAAs under the requirements of 10 CFR 54.21(c)(1)(i), (ii) or (iii) is somewhat dependent 

25 on the process that is used for updating the P-T limits. 

26 For P-T limits that are located in the TS LCOs and are controlled by the 10 CFR 50.90 license 

27 amendment process, the P-T limits are required to be updated and approved by the NRC prior 

28 to expiration of the current P-T limit curves in the TS LCOs, or when a change to the P-T limits 

29 is needed for compliance with the requirements in Section IV.C of 10 CFR Part 50, Appendix H 

30 (Ref. 4). For those plants that have approved PTLRs, the P-T limits are required to be updated 

31 prior to expiration of the current P-T limit curves in the PTLRs, or when a change to the P-T 

32 limits is needed for compliance with the requirements in Section IV.C of 10 CFR Part 50, 

33 Appendix H, or when required by a specific P-T limits update clause in the Administrative 

34 Controls TS Section that governs implementation of the PTLR process. 

35 Specifically, for plants with approved PTLRs, the Administrative Controls TS Section governing 

36 the PTLR process requires that the update of the P-T limits be accomplished using prescribed 

37 methodologies referenced in the TS requirements. NRC generic letter (GL) 96-03 (Ref. 17) 

38 provides the NRC’s position on the minimum requirements that need to be included in the 

39 Administrative Controls TS Section that governs implementation of the PTLR process and the 

40 type of information that need to be included in the NRC-approved methodologies that will be 

41 used to update the P-T limits and PTLRs. The GL identifies that 10 CFR 50.90 license 

42 amendment requests are not necessary for updates of the P-T limit curves if the required 

43 methodologies are used to update the P-T limits in the PTLRs. Since GL 96-03 establishes the 

44 NRC’s position on what needs be included within the scope of the P-T limit methodologies, 
4.2-12 

1 applicants with approved PTLRs may want to verify that the P-T limit methodologies referenced 

2 in the applicable Administrative Controls TS Section for their PTLR processes are still in 

3 conformance with the criteria in GL 96-03 and that a resulting 10 CFR 54.22 (Ref. 18) change of 

4 the TS is not needed for their LRAs. If it is determined that a change to the referenced 

5 methodologies is needed for the LRA, the applicant should submit the changes to the 

6 referenced methodologies as part of a 10 CFR 54.22 implemented license amendment and TS 

7 change request for the LRA. 

8 4.2.3.1.4.1 10 CFR 54.21(c)(1)(i) 

9 If the P-T limits are located in the TS LCOs or the PTLRs (whichever is applicable to CLB) and 

10 the applicant selects the 10 CFR 54.21(c)(1)(i) option as the basis for accepting the TLAA, the 

11 projected neutron fluences for the 1⁄4T and 3⁄4T locations of each of the RPV beltline components 

12 at the end of the subsequent period of extended operation are reviewed to confirm that they are 

13 bounded by the neutron fluences used to develop the existing P-T limit analysis. 

14 4.2.3.1.4.2 10 CFR 54.21(c)(1)(ii) 

15 The documented results of the revised P-T limit analysis based on the projected reduction in 

16 fracture toughness at the end of the subsequent period of extended operation is reviewed for 

17 compliance with 10 CFR Part 50, Appendix G. If the P-T limits are controlled by the TS LCOs, 

18 the reviewer confirms that the updated P-T limits for the facility are submitted as a 

19 10 CFR 54.22 required license amendment and TS change request for the facility. The 

20 reviewer reviews the submitted P-T limit analysis for compliance with requirements in 

21 10 CFR Part 50, Appendix G. If the P-T limits are controlled by an applicable Administrative 

22 Control TS Section and a PTLR process, the updated P-T limits are reviewed to confirm that the 

23 updated P-T limits have been submitted in an updated PTLR that has been included with the 

24 LRA. The P-T limits in the updated PTLR are also reviewed to confirm that the P-T limits have 

25 been calculated in accordance with the methodologies referenced in the applicable 

26 Administrative Controls TS Section for the PTLR process, or if not, that the updated 

27 methodology or methodologies used to generate the updated P-T limits in the PTLR has or have 

28 been submitted as part of a 10 CFR 54.22 implemented license amendment and TS change 

29 request for the LRA. 

30 The P-T limit evaluations are dependent upon the neutron fluence. 

31 4.2.3.1.4.3 10 CFR 54.21(c)(1)(iii) 

32 Updated P-T limits for the subsequent period of extended operation must be established and 

33 implemented prior to entry into the subsequent period of extended operation. The 

34 10 CFR 50.90 (Ref. 10) process for P-T limits located in the TS LCOs or the TS Administrative 

35 Controls Process for P-T limits that are administratively amended through a PTLR process can 

36 be considered adequate AMPs within the scope of 10 CFR 54.21(c)(1)(iii), such that P-T limits 

37 will be maintained through the subsequent period of extended operation. 

38 For plants whose P-T limits are controlled by an applicable Administrative Controls TS Section 

39 and a NRC-approved PTLR process, the methodologies referenced in the applicable TS Section 

40 are reviewed to verify that they will comply with the requirements in 10 CFR Part 50, 

41 Appendix G and conform to the recommended position for minimum methodology contents in 

42 GL 96-03. Otherwise, the methodology bases for generating updates of the P-T limits during 

43 the subsequent period of extended operation are reviewed to determine whether a 
4.2-13 

1 10 CFR 54.22-implemented license amendment and TS change of the methodology 

2 requirements is necessary for the LRA. 

3 For BWRs whose applicants are accepting their P-T limits in accordance with the criterion in 

4 10 CFR 54.21(c )(1)(iii), the NRC staff confirms that the applicant addresses the following 

5 Renewal Applicant Action Item in the NRC staff’s Safety Evaluation Report (SER) for 

6 BWRVIP-74 (Ref. 19). 

7 Action Item 9: Appendix A of BWRVIP-74-A (Ref. 20) indicates that a set of P-T 

8 curves should be developed for the heat-up and cool-down operating conditions 

9 in the plant at a given EFPY in the subsequent period of extended operation. 

10 This means that, for this action item, the applicant has not provided updated curves, but shall 

11 have a procedure for updating P-T limits in accordance with 10 CFR Part 50, Appendix G, that 

12 will cover 80 years. 

13 4.2.3.1.5 Elimination of Boiling Water Reactor Circumferential Weld Inspection 

14 Some BWRs have an approved technical alternative, which eliminates the RPV circumferential 

15 shell weld inspections from the Section XI program for the current license term. Approved 

16 technical alternatives for SLR have yet to be developed. They will be evaluated on a 

17 case-by-case basis to ensure that the aging effects will be managed in accordance with 

18 10 CFR 54.21(c)(1) such that the intended function(s) will be maintained during the subsequent 

19 period of extended operation. 

20 4.2.3.1.6 Boiling Water Reactor Axial Welds 

21 Those BWRs that have been approved to use the circumferential weld technical alternative also 

22 had to justify acceptable conditional probability of failure for their RPV axial shell weld 

23 examination coverage from the Section XI program for the current license term. Approved 

24 technical alternatives for SLR have yet to be developed. They will be evaluated on a 

25 case-by-case basis to ensure that the aging effects will be managed in accordance with 

26 10 CFR 54.21(c)(1) such that the intended function(s) will be maintained during the subsequent 

27 period of extended operation. 

28 4.2.3.2 Final Safety Analysis Report Supplement 

29 The reviewer verifies that the applicant has provided information to be included in the FSAR 

30 supplement that includes a summary description of the evaluation of the RPV neutron 

31 embrittlement TLAA. Table 4.2-1 of this review plan section contains examples of acceptable 

32 FSAR supplement information for this TLAA. The reviewer verifies that the applicant has 

33 provided an FSAR supplement with information equivalent to that in Table 4.2-1. 

34 The NRC staff expects to impose a license condition on any renewed license to require the 

35 applicant to update its FSAR to include this FSAR supplement at the next update required 

36 pursuant to 10 CFR 50.71(e)(4) (Ref. 21). As part of the license condition, until the FSAR 

37 update is complete, the applicant may make changes to the programs described in its FSAR 

38 supplement without prior NRC approval, provided that the applicant evaluates each such 

39 change pursuant to the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR 

40 to include the final FSAR supplement before the license is renewed, no condition will 

41 be necessary. 
4.2-14 

1 As noted in Table 4.2-1, an applicant need not incorporate the implementation schedule into its 

2 FSAR. However, the reviewer should verify that the applicant has identified and committed in 

3 the SLRA to any future aging management activities, including enhancements and 

4 commitments to be completed before the subsequent period of extended operation. The NRC 

5 staff expects to impose a license condition on any renewed license to ensure that the applicant 

6 will complete these activities no later than the committed date. 

7 4.2.4 Evaluation Findings 

8 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

9 provisions of this section and whether the NRC staff’s evaluation supports conclusions of the 

10 following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

11 included in the SER: 

12 On the basis of its review, as discussed above, the NRC staff concludes that the 

13 applicant has provided an acceptable demonstration, pursuant to 10 CFR 

14 54.21(c)(1), that, for the RPV neutron embrittlement TLAA, [choose which is 

15 appropriate] (i) the analyses remain valid for the subsequent period of extended 

16 operation, (ii) the analyses have been projected to the end of the subsequent 

17 period of extended operation, or (iii) the effects of aging on the intended 

18 function(s) will be adequately managed for the subsequent period of extended 

19 operation. The NRC staff also concludes that the FSAR supplement contains an 

20 appropriate summary description of the RPV neutron embrittlement TLAA 

21 evaluation for the subsequent period of extended operation as reflected in the 

22 license condition. 

23 4.2.5 Implementation 

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

25 method described herein will be used by the NRC staff in its evaluation of conformance with 

26 NRC regulations. 

27 4.2.6 References 

28 1. NRC. Regulatory Information Summary (RIS) No. 2014-11, “Information on Licensing 

29 Applications For Fracture Toughness Requirements For Ferritic Reactor Coolant 

30 Pressure Boundary Components.” ML14149A165. Washington, DC: U.S. Nuclear 

31 Regulatory Commission. October 14, 2014. 

32 2. 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power 

33 Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

34 3. 10 CFR Part 54.21, “Contents of Application–Technical Information.” Washington, DC: 

35 U.S. Nuclear Regulatory Commission. 2015. 

36 4. 10 CFR Part 50, “Appendix H, Reactor Vessel Material Surveillance Program 

37 Requirements.” Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

38 5. NRC. Regulatory Guide 1.190, “Calculational and Dosimetry Methods for Determining 

39 Pressure Vessel Neutron Fluence.” Revision 0. Washington, DC: U.S. Nuclear 

40 Regulatory Commission. 2001. 
4.2-15 

1 6. 10 CFR Part 50, “Fracture Toughness Requirements.” Appendix G. Washington, DC: 

2 U.S. Nuclear Regulatory Commission. 2015. 

3 7. 10 CFR Part 50.61, “Fracture Toughness Requirements for Protection Against 

4 Pressurized Thermal Shock Events.” Washington, DC: U.S. Nuclear Regulatory 

5 Commission. 2015. 

6 8. 10 CFR Part 50.61a, “Alternate Fracture Toughness Requirements for Protection 

7 Against Pressurized Thermal Shock Events.” Washington, DC: U.S. Nuclear 

8 Regulatory Commission. 2015. 

9 9. L.A. Reyes. Letter (May 27) to the Commission. ML041190564. Washington, DC: 

10 U.S. Nuclear Regulatory Commission. 2004. 

11 10. 10 CFR Part 50.90, “Application for Amendment of License, Construction Permit, or 

12 Early Site Permit.” Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

13 11. 10 CFR Part 50.59, “Changes, Tests, and Experiments.” Washington, DC: U.S. Nuclear 

14 Regulatory Commission. 2015. 

15 12. NRC. Regulatory Guide 1.99, “Radiation Embrittlement of Reactor Vessel Materials.” 

16 Revision 2. May, 1988. 

17 13. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components, 

18 Nonmandatory Appendix K, “Assessment of Reactor Vessels with Low Upper Shelf 

19 Charpy Impact Energy Levels.” New York City, New York. 2010. 

20 14. NRC. NUREG–0800, “U.S. Nuclear Regulatory Commission, Standard Review Plan.” 

21 Washington, DC: U.S. Nuclear Regulatory Commission. March 2007. 

22 15. NRC. Regulatory Guide 1.154, “Format and Content of Plant-Specific Pressurized 

23 Thermal Shock Safety Analysis Reports for Pressurized Water Reactors.” 

24 Washington, DC: U.S. Nuclear Regulatory Commission. January 1987. 

25 16. 10 CFR Part 50.36, “Technical Specifications.” Washington, DC: U.S. Nuclear 

26 Regulatory Commission. 2015. 

27 17. NRC. Generic Letter 96-03, “Relocation of the Pressure Temperature Limit Curves and 

28 Lower Temperature Overpressure Protection System Limits.” Washington, DC: 

29 U.S. Nuclear Regulatory Commission. 1996. 

30 18. 10 CFR Part 54.22, “Contents of Application – Technical Specifications.” 

31 Washington, DC: U.S. Nuclear Regulatory Commission. 2015. 

32 19. Christopher Grimes. Letter (October 18) to Carl Terry of Niagara Mohawk Power 

33 Company, BWRVIP Chairman, “Acceptance for Referencing of EPRI Proprietary Report 

34 TR-113596, BWR Vessel and Internals Project, BWR Reactor Pressure Vessel 

35 Inspection and Flaw Evaluation Guidelines BWRVIP-74), and Appendix A, 

36 Demonstration of Compliance with the Technical Information Requirements of the 

37 License Renewal Rule (10CFR54.21).” Washington, DC: U.S. Nuclear Regulatory 

38 Commission. 2001. 
4.2-16 

1 20. EPRI. TR-1008872, “BWRVIP-74-A, BWR Vessels and Internals Project, BWR Reactor 

2 Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal.” 

3 Palo Aldo, California: Electric Power Research Institute. June 2003. 

4 21. 10 CFR Part 50.71, “Maintenance of Records, Making of Reports.” Washington, DC: 

5 U.S. Nuclear Regulatory Commission. 2015. 
4.2-17 

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

Embrittlement Analyses 

TLAA Description of Evaluation Implementation 

Schedule* 

Neutron Fluence 

Example for 

acceptance per 

§54.21(c)(1)(iii) 

The neutron fluence of each beltline material for the 

subsequent period of extended operation has been 

calculated in accordance with the guidance in RG 

1.190. The neutron fluence is monitored through the 

subsequent period of extended operation by using 

GALL-SLR Report AMP X.M2, “Neutron Fluence 

Monitoring.” 

Ongoing through 

AMP monitoring 

Upper-shelf 

energy 

Example for 

acceptance per 

§54.21(c)(1)(ii) 

10 CFR Part 50 Appendix G paragraph IV.A.1 

requires that the RPV beltline materials must have 

Charpy upper-shelf energy of no less than 50 ft-lb (68 

J) throughout the life of the RPV unless otherwise 

approved by the NRC. The upper-shelf energy has 

been determined to exceed 50 ft-lb (68 J) to the end 

of the subsequent period of extended operation. 

Completed 

Pressurized 

thermal shock 

(for PWRs) 

Example for 

acceptance per 

§54.21(c)(1)(ii) 

For PWRs, 10 CFR 50.61 requires the reference 

temperature RTPTS for RPV beltline materials to be 

less than the PTS screening criteria at the expiration 

date of the operating license unless otherwise 

approved by the NRC. The reference temperature 

has been determined to be less than the PTS 

screening criteria at the end of the subsequent period 

of extended operation, unless alternate requirements 

have been invoked in accordance with 10 CFR 

50.61(b) and approved by the NRC. 

Completed 

Pressuretemperature 

(P-T) limits 

Example for 

acceptance per 

§54.21(c)(1)(iii) 

10 CFR Part 50 Appendix G requires that heatup and 

cooldown of the RPV be accomplished within 

established P-T limits. These limits specify the 

maximum allowable pressure as a function of reactor 

coolant temperature. As the RPV becomes 

embrittled and its fracture toughness is reduced, the 

allowable pressure is reduced. 10 CFR Part 50 

Appendix G requires periodic update of P-T limits 

based on projected embrittlement and data from a 

material surveillance program. The P-T limits will be 

updated to consider the subsequent period of 

extended operation. 

For P-T limits 

controlled by TS 

LCOs: 10 CFR 

50.90 Update 

should be 

completed and 

approved by the 

NRC before the 

subsequent period 

of extended 

operation 

For P-T limits 

controlled by TS 

PTLR requirements: 

Update should be 

completed before 

the subsequent 

period of extended 

operation and 

updated PTLR 

containing the 
4.2-18 

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

Embrittlement Analyses 

updated P-T limits 

submitted to the 

NRC in accordance 

applicable 

Administrative 

Control TS 

reporting 

requirements 

Elimination of 

BWR 

circumferential 

weld inspections 

and analysis of 

BWR axial welds 

[Not applicable - approved technical alternatives for 

SLR have yet to be developed] 

Not applicable 

Other 

miscellaneous 

TLAAs on RV 

neutron 

embrittlement 

Provide sufficient information on how the calculations 

for plant-specific TLAAs were performed, what the 

limiting TLAA parameter was calculated to be in 

accordance with the neutron fluence projected for the 

subsequent period of extended operation, and why 

the TLAA is acceptable under either 10 CFR 54.21 

(c)(1)(i), (ii), or (iii). 

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

that the applicant has identified and committed in the SLRA to any future aging management activities to be 

completed before the subsequent period of extended operation. The staff expects to impose a license condition on 

any renewed license to ensure that the applicant will complete these activities by no later than the committed date. 
4.3-1 

1 4.3 Metal Fatigue 

2 Review Responsibilities 

3 Primary—Branch responsible for the time-limited aging analysis (TLAA) issues 

4 Secondary—None 

5 4.3.1 Area of Review 

6 Fatigue occurs in a metal component when it is subjected to fluctuating loads. If the loading is 

7 of sufficient magnitude or frequency, cracks may initiate and propagate in the component at the 

8 location of maximum loading. To address fatigue concerns, Section III of the American Society 

9 of Mechanical Engineers (ASME) Code requires a fatigue analysis for Class 1 components. 

10 The analysis must consider all expected cyclic loads based on the anticipated number of cyclic 

11 loadings. In the most rigorous evaluation, the ASME Code provisions include the calculation of 

12 the cumulative usage factor (CUF) for selected locations within a component, which is a 

13 calculated measure of the expended fatigue initiation life at each location in the component. 

14 Under these provisions, the ASME Code limits the CUF to a value of less than or equal to unity 

15 for acceptable fatigue design. A CUF below a value of unity provides assurance that no crack 

16 has initiated at the analyzed location in the component. Other provisions in Section III of the 

17 ASME Code allow less rigorous treatment to address the fatigue design in components that 

18 have smaller or less frequent cyclic loadings, (i.e., fatigue waiver evaluation). In some cases, 

19 continued adequacy of the fatigue life of a component may be demonstrated through 

20 reinspections that continue to demonstrate an absence of fatigue flaws, (i.e., flaw tolerance 

21 evaluation). In other cases, the growth of fatigue flaws is assessed to ensure that flaws 

22 detected in components remain within allowable limits. 

23 The acceptability of metal components from a fatigue standpoint is demonstrated by one or 

24 more relevant fatigue parameters, which include, but are not limited to, the CUF values, the 

25 environmentally-adjusted CUFen values, transient cycle limits, and predicted flaw sizes 

26 (for fatigue flaw tolerance or component flaw evaluations). The limits of the fatigue parameters 

27 are established by the applicable fatigue analyses and may be a design limit, for example from 

28 an ASME Code fatigue evaluation, or an analysis-specific value, for example based on the 

29 number of cyclic load occurrences assumed in fatigue waiver evaluations or the acceptable flaw 

30 sizes postulated in flaw tolerance or component flaw evaluations. 

31 As a result of the assumptions used in the underlying evaluations associated with metal 

32 component fatigue parameters (i.e., the magnitude and frequency of the assumed cyclic 

33 loadings for the future operating life of the component), the continued validity of metal fatigue 

34 analyses is reviewed for the subsequent period of extended operation. 

35 Areas of review to ensure that the metal component fatigue parameter evaluations are valid for 

36 the subsequent period of extended operation include: 

37 1. CUF calculations or fatigue waiver evaluations for components designed using the fatigue 

38 requirements of Section III of the ASME Code or other Codes that use a It calculation 

39 [e.g., the 1969 edition of ANSI B31.7 for Class 1 piping, ASME NC-3200 vessels, 

40 ASME NE-3200 Class MC components, ASME NG-3200 core support structures, and 
4.3-2 

1 metal bellows designed to ASME NC-3649.4(e)(3), ND-3649.4(e)(3), or NE-3366.2(e)(3)] 

2 or the Draft ASME Code for Pumps and Valves for It analyses). 

3 2. Fatigue-based maximum allowable stress calculations for components evaluated to 

4 United States of America Standards (USAS) American National Standards Institute 

5 (ANSI) B31.1 or ASME Code Class 2 and 3 requirements. 

6 3. CUF calculations for components that require evaluation of environmental effects 

7 (CUFen). 

8 4. Fatigue-based flaw growth, flaw tolerance, or fracture mechanics analyses, including 

9 those used to support reinspection intervals for components. 

10 4.3.2 Acceptance Criteria 

11 Acceptance criteria are provided in the following subsections for the areas of review described 

12 in Subsection 4.3.1 that delineate acceptable methods for meeting the requirements of the 

13 U.S. Nuclear Regulatory Commission (NRC) regulations in Title 10 of the Code of Federal 

14 Regulations (10 CFR) 54.21(c)(1). 

15 4.3.2.1 Time-Limited Aging Analysis 

16 Pursuant to 10 CFR 54.21(c)(1)(i) through (iii), an applicant must demonstrate one of the 

17 following for each analysis: 

18 i. The analyses remain valid for the period of extended operation: 

19 ii. The analyses have been projected to the end of the period of extended operation; or 

20 iii. The effects of aging on the intended function(s) will be adequately managed for the 

21 period of extended operation. 

22 In some instances, the applicant may identify activities to be performed to verify the assumption 

23 bases of the fatigue analyses. Evaluations of those activities are provided by the applicant. 

24 The reviewer assures that the applicant’s activities are sufficient to confirm the calculation 

25 assumptions for the subsequent period of extended operation. 

26 Specific acceptance criteria for metal component fatigue evaluations are discussed in the 

27 following subsections. 

28 4.3.2.1.1 Components Evaluated for Fatigue Parameters Other than CUFen

29 For metal components evaluated for fatigue parameters other than CUFen, the acceptance 

30 criteria depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are as follows: 

31 4.3.2.1.1.1 10 CFR 54.21(c)(1)(i) 

32 The existing fatigue parameter calculations remain valid for the subsequent period of extended 

33 operation because the number of accumulated cycles and the assumed severity of each of the 

34 cyclic loadings evaluated in the calculations are not projected to exceed the limits evaluated for 
4.3-3 

1 these loadings. The revised projections are verified to be consistent with historical plant 

2 operating characteristics and anticipated future operation. 

3 4.3.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

4 The fatigue parameter calculations are revised and shown to remain acceptable throughout the 

5 subsequent period of extended operation based on a revised projection of the cumulative 

6 number and assumed severity of each of the cyclic loadings to the end of the subsequent period 

7 of extended operation. The revised projections are verified to be consistent with historical plant 

8 operating characteristics and anticipated future operation. The resulting fatigue parameter 

9 values are verified to remain less than or equal to their respective allowable value for the 

10 subsequent period of extended operation. 

11 4.3.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

12 The applicant proposes an aging management program (AMP) as the basis for demonstrating 

13 that the effect or effects of aging on the intended function(s) of the structure(s) or component(s) 

14 in the fatigue parameter evaluations will be adequately managed during the subsequent period 

15 of extended operation. The AMP in Section X.M1, “Cyclic Load Monitoring,” of the Generic 

16 Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) report provides one 

17 method that may be used to demonstrate compliance with the requirement in 

18 10 CFR 54.21(c)(1)(iii). 

19 An applicant may also propose another AMP to demonstrate compliance with the requirement in 

20 10 CFR 54.21(c)(1)(iii). If the basis for aging management is a plant-specific AMP, the AMP is 

21 described in terms of the 10 program elements defined in the Standard Review Plan for Review 

22 of Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR), 

23 Appendix A.1, “Branch Technical Position, Aging Management Review—Generic,” 

24 Sections A.1.2.3.1 through A–1.2.3.10. 

25 If an inspection program is proposed as the basis for aging management, the applicant should 

26 ensure that: (a) inspections will be performed for the specific component(s) or structure(s) in 

27 the evaluation and (b) applicant has justified that the inspection methods and frequencies in the 

28 proposed inspection program are applicable to the component(s), such that they may be used to 

29 demonstrate compliance with the requirement in 10 CFR 54.21(c)(1)(iii). 

30 4.3.2.1.2 Components Evaluated for CUFen

31 For metal components evaluated for CUFen, the acceptance criteria depend on the applicant’s 

32 choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

33 Applicants should also include CUFen calculations for additional component locations if they are 

34 considered to be more limiting than those previously evaluated. The sample of critical 

35 components can be evaluated by applying environmental correction factors to the existing CUF 

36 analyses or by performing more refined calculations. Environmental effects on fatigue for 

37 these critical components can be evaluated using the positions described in Regulatory Guide 

38 (RG) 1.207, Revision 1 (Ref. 5) or an NRC staff-approved alternative. 
4.3-4 

1 4.3.2.1.2.1 10 CFR 54.21(c)(1)(i) 

2 The existing CUFen calculations remain valid for the subsequent period of extended operation 

3 because the number of accumulated cycles, the assumed severity of the cyclic loadings, and 

4 the assumed water chemistry conditions evaluated in the calculations are not projected to 

5 exceed the limits evaluated for these loadings. The revised projections for the number of 

6 accumulated cycles are verified to be consistent with historical plant operating characteristics 

7 and anticipated future operation. 

8 For stainless steel (SS) and nickel alloy materials, or any location where average temperature 

9 was used in the calculation, or where a constant Fen value of 1.49 was used for nickel alloy 

10 materials, the methods are updated under 10 CFR 54.21(c)(1)(ii) to use the positions described 

11 in RG 1.207, Revision 1. 

12 4.3.2.1.2.2 10 CFR 54.21(c)(1)(ii) 

13 The CUFen calculations are revised and shown to remain acceptable throughout the subsequent 

14 period of extended operation based on a revised projection of the cumulative number of 

15 occurrences, the assumed severity of cyclic loadings, and the assumed water chemistry 

16 conditions to the end of the subsequent period of extended operation. The revised projections 

17 are verified to be consistent with historical plant operating characteristics and anticipated future 

18 operation. The resulting CUFen values are verified to remain less than or equal to unity for the 

19 subsequent period of extended operation. The positions described in RG 1.207, Revision 1 are 

20 used for all component evaluations as a part of revising the calculations. 

21 4.3.2.1.2.3 10 CFR 54.21(c)(1)(iii) 

22 In Section X.M1 of the GALL-SLR Report, the NRC staff evaluated a program for monitoring 

23 and tracking the number of occurrences and the severity of critical cyclic loadings for selected 

24 components. In Section XI.M2 of the GALL-SLR Report, the NRC staff evaluated a program for 

25 monitoring and tracking water chemistry conditions. The NRC staff determined that these 

26 programs, when used together, are acceptable AMPs to address the effects of reactor water 

27 environment on component fatigue life according to 10 CFR 54.21(c)(1)(iii). The GALL-SLR 

28 Report may be referenced in an subsequent license renewal application (SLRA) and should be 

29 treated in the same manner as an approved topical report. In referencing the GALL-SLR 

30 Report, the applicant should indicate that the material referenced is applicable to the specific 

31 plant involved and should provide the information necessary to adopt the finding of program 

32 acceptability as described and evaluated in the report. The applicant also should verify that 

33 the approvals set forth in the GALL-SLR Report for the generic program apply to the 

34 applicant’s program. Alternatively, the components could be replaced and the CUFen values 

35 for the replacement components shown to be acceptable for the subsequent period of 

36 extended operation. 

37 4.3.2.2 Final Safety Analysis Report Supplement 

38 The specific criterion for meeting 10 CFR 54.21(d) is as follows: 

39 The summary description of the evaluation of TLAAs for the subsequent period of extended 

40 operation in the Final Safety Analysis Report (FSAR) supplement is appropriate such that later 

41 changes can be controlled by 10 CFR 50.59. The description should contain information 
4.3-5 

1 associated with the TLAAs regarding the basis for determining that the applicant has made the 

2 demonstration required by 10 CFR 54.21(c)(1). 

3 4.3.3 Review Procedures 

4 Review procedures for metal component fatigue parameter evaluations for the areas of review 

5 described in Subsection 4.3.1 are discussed in the following subsections. 

6 4.3.3.1 Time-Limited Aging Analysis 

7 The Code of Record should be used for the re-evaluation, or the applicant may update to a later 

8 Code edition pursuant to 10 CFR 50.55a using an appropriate Code reconciliation. In the latter 

9 case, the reviewer verifies that the requirements in 10 CFR 50.55a are met. 

10 4.3.3.1.1 Components Evaluated for Fatigue Parameters Other Than CUFen

11 For metal components evaluated for fatigue parameters other than CUFen, the review 

12 procedures depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are 

13 as follows: 

14 4.3.3.1.1.1 10 CFR 54.21(c)(1)(i) 

15 The operating cyclic load experience and a list of the assumed transients used in the existing 

16 fatigue parameter calculations is reviewed for the current operating term to ensure that the 

17 projected number of transient occurrences during the subsequent period of extended operation 

18 will not exceed the assumed number of transient occurrences in the existing fatigue parameter 

19 calculations. The projected number of occurrences for each transient is verified to be consistent 

20 with historical plant operating characteristics and anticipated future operation. In addition, a 

21 comparison of the operating cyclic load severity to the severity for each transient assumed in 

22 the existing fatigue parameter calculations is made to demonstrate that the cyclic load severity 

23 for each transient used in the fatigue parameter calculations remains bounding. For 

24 consistency purposes, the review also includes an assessment of the TLAA information against 

25 relevant design basis information and current licensing basis (CLB) information. 

26 4.3.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

27 The operating cyclic load experience is reviewed to ensure that the increased number of cyclic 

28 load occurrences and their severity for each transient used for any reanalysis remain within the 

29 number of transient occurrences and severity for each transient projected to the end of the 

30 subsequent period of extended operation. The revised fatigue parameter calculations are 

31 reviewed to ensure that the fatigue parameter remains less than or equal to the allowed value at 

32 the end of the subsequent period of extended operation. The revised fatigue parameter 

33 calculations are shown to remain acceptable based on revised projections of the cumulative 

34 number of occurrences and the assumed severity of each transient to the end of the subsequent 

35 period of extended operation. The revised projections are verified to be consistent with 

36 historical plant operating characteristics and anticipated future operation. For consistency 

37 purposes, the review also includes an assessment of the TLAA information against relevant 

38 design basis information and CLB information. 
4.3-6 

1 4.3.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

2 Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant proposes an AMP or aging management 

3 activities as the basis for demonstrating that the effect or effects of aging on the intended 

4 function(s) of the structure(s) or component(s) in the fatigue parameter evaluation will be 

5 adequately managed during the subsequent period of extended operation. If Section X.M1, 

6 “Cyclic Load Monitoring,” of the GALL-SLR Report is used as the basis for managing cumulative 

7 fatigue damage or cracking due to fatigue or cyclical loading in the structure(s) or component(s), 

8 the reviewer reviews the applicant’s AMP against the program elements defined in GALL-SLR 

9 Report Section X.M1. 

10 An applicant also has the option of proposing another GALL-based AMP, plant-specific AMP, or 

11 plant-specific activities, or combination of, to demonstrate compliance with the requirement in 

12 10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

13 management, the reviewer reviews the applicant’s AMP against the program element criteria 

14 defined in the applicable AMP section in Chapter XI of the GALL-SLR Report. If the basis for 

15 aging management is a plant-specific AMP or plant-specific aging management activities, the 

16 reviewer reviews the program element criteria for the AMP or activities against the program 

17 element criteria defined in this SRP-SLR, Appendix A.1, “Branch Technical Position, Aging 

18 Management Review—Generic,” Sections A.1.2.3.1 through A.1.2.3.10. 

19 If a sampling based inspection program (a type of condition monitoring program) is proposed as 

20 the basis for aging management, the reviewer ensures that the AMP actually performs 

21 inspections of the specific component(s) or structure(s) in the evaluation at each unit in a 

22 multiunit site and that the applicant has appropriately justified that the inspection methods and 

23 associated frequencies are capable of managing cumulative fatigue damage or cracking by 

24 fatigue or cyclical loading in the component(s) or structure(s), such that the TLAA may be 

25 accepted in accordance with 10 CFR 54.21(c)(1)(iii). 

26 4.3.3.1.2 Components Evaluated for CUFen

27 For metal components evaluated for CUFen, the review procedures depend on the applicant’s 

28 choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

29 Applicants should include CUFen calculations for the limiting component locations exposed to 

30 the reactor water environment. A sample of critical components can be evaluated by applying 

31 environmental correction factors to the existing CUF analyses or by performing more refined 

32 calculations. Environmental effects on fatigue for these critical components can be evaluated 

33 using the positions described in RG 1.207, Revision 1, or a NRC staff-approved alternative. 

34 4.3.3.1.2.1 10 CFR 54.21(c)(1)(i) 

35 The operating cyclic load experience and a list of the assumed transients used in the existing 

36 fatigue parameter calculations are reviewed for the current operating term to ensure that the 

37 number of assumed occurrences of each transient would not be exceeded during the 

38 subsequent period of extended operation. A comparison of the operating cyclic load severity to 

39 the severity assumed in the existing fatigue parameter calculations for each transient should be 

40 made to demonstrate that the cyclic load severities used in the fatigue parameter calculations 

41 remain bounding. In addition, a comparison of the water chemistry conditions to those assumed 

42 in the existing environmental multiplier (Fen) calculations should be made to demonstrate that 

43 the water chemistry conditions used in the Fen calculations remain appropriate. For consistency 
4.3-7 

1 purposes, the review also includes an assessment of the TLAA information against relevant 

2 design basis information and CLB information. For SS and nickel alloy materials, or any 

3 location where average temperature was used in the calculation, or where a constant Fen value 

4 of 1.49 was used for nickel alloy materials, the review includes verification that the methods 

5 have been updated to use the positions described in RG 1.207, Revision 1 under the provisions 

6 of 10 CFR 54.21(c)(1)(ii). 

7 4.3.3.1.2.2 10 CFR 54.21(c)(1)(ii) 

8 The operating cyclic load experience and a list of the assumed transients used in the existing 

9 fatigue parameter calculations is reviewed for the current operating term to ensure that the 

10 number of assumed occurrences for each transient are projected to the end of the subsequent 

11 period of extended operation. The reviewer verifies that a comparison of the operating cyclic 

12 load severity to the severity assumed in the existing fatigue parameter calculations for each 

13 transient has been made to demonstrate that the cyclic load severities used in the fatigue 

14 parameter calculations remain bounding. In addition, the reviewer verifies that a comparison of 

15 the water chemistry conditions to those assumed in the Fen calculations has been made to 

16 demonstrate that the water chemistry conditions used in the Fen calculations are appropriate. 

17 For consistency purposes, the review also includes an assessment of the TLAA information 

18 against relevant design basis information and CLB information. The review includes verification 

19 that the positions described in RG 1.207, Revision 1 are used for all component evaluations as 

20 a part of revising the calculations. 

21 The Code of Record should be used for the reevaluation, or the applicant may update to a later 

22 Code edition pursuant to 10 CFR 50.55a using an appropriate Code reconciliation. In the latter 

23 case, the reviewer verifies that the requirements in 10 CFR 50.55a are met. 

24 4.3.3.1.2.3 10 CFR 54.21(c)(1)(iii) 

25 The applicant may reference Sections X.M1 and XI.M2 of the GALL-SLR Report in its SLR 

26 application and use these GALL-SLR chapters to accept the TLAA in accordance with 

27 10 CFR 54.21(c)(1)(iii), as appropriate. The review should verify that the applicant has stated 

28 that the report is applicable to its plant with respect to its program that monitors and tracks the 

29 number and severity of critical cyclic loadings and water chemistry conditions for metal 

30 components. The reviewer verifies that the applicant has identified the appropriate programs as 

31 described and evaluated in the GALL-SLR Report. The reviewer also ensures that the applicant 

32 has stated that its program contains the same program elements that the NRC staff evaluated 

33 and relied upon in approving the corresponding generic program in the GALL-SLR Report. For 

34 consistency purposes, the review also includes an assessment of the TLAA information against 

35 relevant design basis and CLB information (including applicable cycle-counting requirements 

36 and water chemistry monitoring set forth in the applicable AMPs). 

37 An applicant also has the option of proposing another GALL-based AMP, plant-specific AMP, or 

38 plant-specific activities, or combination of, to demonstrate compliance with the requirement in 

39 10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

40 management, the reviewer reviews the applicant’s AMP against the program element criteria 

41 defined in the applicable AMP section in Chapter XI of the GALL-SLR Report. If the basis for 

42 aging management is a plant-specific AMP or plant-specific aging management activities, the 

43 reviewer reviews the program element criteria for the AMP or activities against the program 

44 element criteria defined in this SRP-SLR, Appendix A.1, “Branch Technical Position, Aging 

45 Management Review—Generic,” Sections A.1.2.3.1 through A.1.2.3.10. 
4.3-8 

1 If a sampling based inspection program (a type of condition monitoring program) is proposed as 

2 the basis for aging management, the reviewer ensures that the AMP actually performs 

3 inspections of the specific component(s) or structure(s) in the evaluation at each unit in a 

4 multiunit site and that the applicant has appropriately justified that the inspection methods and 

5 associated frequencies are capable of managing cumulative fatigue damage or cracking by 

6 fatigue or cyclical loading in the component(s) or structure(s), such that the TLAA may be 

7 accepted in accordance with 10 CFR 54.21(c)(1)(iii). 

8 4.3.3.2 Final Safety Analysis Report Supplement 

9 The reviewer verifies that the applicant has provided information to be included in the FSAR 

10 supplement that includes a summary description of the evaluation of the metal fatigue TLAA. 

11 Table 4.3-1 contains examples of acceptable FSAR supplement information for metal fatigue 

12 TLAAs that are dispositioned in accordance with 10 CFR 54.21(c)(1)(iii). The reviewer verifies 

13 that the applicant has provided a FSAR supplement with information equivalent to that in 

14 Table 4.3-1. 

15 The NRC staff expects to impose a license condition on any renewed license to require the 

16 applicant to update its FSAR to include this FSAR supplement at the next update required 

17 pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

18 complete, the applicant may make changes to the programs described in its FSAR supplement 

19 without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

20 the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final 

21 FSAR supplement before the license is renewed, no condition will be necessary. 

22 As noted in Table 4.3-1, an applicant need not incorporate the implementation schedule into its 

23 FSAR. However, the reviewer should verify that the applicant has identified and committed in 

24 the license renewal application to any future aging management activities, including 

25 enhancements and commitments to be completed before the start of the subsequent period of 

26 extended operation. The NRC staff expects to impose a license condition on any renewed 

27 license to ensure that the applicant will complete these activities no later than the 

28 committed date. 

29 4.3.4 Evaluation Findings 

30 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

31 provisions of this section and whether the NRC staff’s evaluation supports conclusions of the 

32 following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

33 included in the NRC staff’s Safety Evaluation Report: 

34 On the basis of its review, as discussed above, the NRC staff concludes that 

35 the applicant has provided an acceptable demonstration, pursuant to 

36 10 CFR 54.21(c)(1), that, for the [reviewer to insert applicable type of metal 

37 fatigue analysis] TLAA, [choose which is appropriate] (i) the analyses remain 

38 valid for the subsequent period of extended operation, (ii) the analyses have 

39 been projected to the end of the subsequent period of extended operation, or 

40 (iii) the effects of aging on the intended function(s) will be adequately managed 

41 for the subsequent period of extended operation. The NRC staff also concludes 

42 that the FSAR Supplement contains an appropriate summary description of the 

43 [reviewer to insert applicable type of metal fatigue analysis] TLAA, evaluation for 

44 the subsequent period of extended operation as reflected in the license condition. 
4.3-9 

1 4.3.5 Implementation 

2 Except in those cases where the applicant proposes an acceptable alternative, the methods 

3 described herein will be used by the NRC staff in its evaluations of conformance with 

4 NRC regulations. 

5 4.3.6 References 

6 1. ASME. “Rules for Construction of Nuclear Power Plant Components.” ASME Boiler and 

7 Pressure Vessel Code, Section III. New York City, New York: American Society of 

8 Mechanical Engineers. 

9 2. ANSI/ASME B31.1, “Power Piping.” New York City, New York: American National 

10 Standards Institute. 

11 3. ANSI/ASME B31.7-1969, “Nuclear Power Piping.” New York City, New York: American 

12 National Standards Institute. 

13 4. NRC. Regulatory Guide 1.207, “Guidelines for Evaluating the Effects of Light-Water 

14 Reactor Coolant Environments in Fatigue Analyses of Metal Components.” Revision 1. 

15 Washington, DC: U.S. Nuclear Regulatory Commission. 2014. 

16 5. NRC. NUREG/CR-6909, Revision 1, ANL-12/60, “Effect of LWR Coolant Environments 

17 on the Fatigue Life of Reactor Materials.” ML14087A068. Washington, DC: U.S. 

18 Nuclear Regulatory Commission. March 2014. 

19 6. ASME. Section III, “Rules for Construction of Nuclear Facility Components.” 

20 New York City, New York: American Society of Mechanical Engineers. 

21 7. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components, 

22 Nonmandatory, Appendix A, Analysis of Flaws.” New York City, New York: American 

23 Society of Mechanical Engineers. 

24 8. ASME. Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components, 

25 Appendix C, Evaluation of Flaws in Austenitic Piping.” New York City, New York: 

26 American Society of Mechanical Engineers. 
4.3-10 

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

10 CFR 54.21(c)(1)(i) Examples 

TLAA Description of Evaluation Implementation Schedule*

Components Evaluated for Fatigue Parameters Other than CUFen

[Applicant to identify and provide adequate description of the specific metal fatigue parameter evaluation] The number of occurrences and severity of each of the thermal and pressure transients, projected to the end of the subsequent license renewal operating period, demonstrate that the [Applicant to insert Name of the TLAA] remains valid during the subsequent license renewal operating period and therefore, that this TLAA is acceptable in accordance with the criterion in 10 CFR 54.21(c)(1)(i). 

Completed (prior to submittal of an application for SLR) 

Components Evaluated for CUFen

[Applicant to identify and provide adequate description of the specific metal fatigue evaluation for evaluating environmentally assisted fatigue in ASME Code Class 1 or Safety Class 1 components] The effects of the water environment on component fatigue life have been addressed by assessing the impact of the water environment on the limiting component locations, using the positions described in Regulatory Guide 1.207, Revision 1. The number of occurrences and severity of each of the thermal and pressure transients, projected to the end of the subsequent license renewal operating period, and consideration of the water chemistry parameters demonstrate that the TLAA on environmentally assisted fatigue remains valid during the subsequent license renewal operating period and therefore, that this TLAA is acceptable in accordance with 10 CFR 54.21(c)(1)(i). 

Completed (prior to submittal of an application for SLR) 

10 CFR 54.21(c)(1)(ii) Examples

TLAA Description of Evaluation Implementation Schedule*

Components Evaluated for Fatigue Parameters Other than CUFen

[Applicant to identify and provide adequate description of the specific metal fatigue parameter evaluation] The analysis has been projected to the end of the subsequent license renewal operating period, considering the number of occurrences and severity of each of the thermal and pressure transients, and demonstrates that the TLAA is acceptable in accordance with 10 CFR 54.21(c)(1)(ii). 

Completed (prior to submittal of an application for SLR) 

Components Evaluated for CUFen

Applicant to identify and provide adequate description of the specific metal fatigue evaluation for evaluating environmentally assisted fatigue in ASME Code Class 1 or Safety Class 1 components] 

Completed (prior to submittal of an application for SLR) 
4.3-11 

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

10 CFR 54.21(c)(1)(i) Examples 

TLAA Description of Evaluation Implementation Schedule*

The effects of the water environment on component fatigue life have been addressed by assessing the impact of the water environment on the limiting component locations, using the positions described in Regulatory Guide 1.207, Revision 1. The analysis for environmentally-assisted fatigue has been projected to the end of the subsequent license renewal operating period, considering the number of occurrences and severity of each of the thermal and pressure transients and the water chemistry parameters, and demonstrates that the TLAA is acceptable in accordance with 10 CFR 54.21(c)(1)(ii). 

10 CFR 54.21(c)(1)(iii) Examples

TLAA Description of Evaluation Implementation Schedule*

Components Evaluated for Fatigue Parameters Other than CUFen

Fatigue evaluations were performed to ensure the continued validity of the metal fatigue analyses for the subsequent license renewal operating period. [Applicant to provide adequate description of the specific metal fatigue parameter 

evaluation] The AMP monitors and tracks the number of occurrences and severity of thermal and pressure transients, and requires corrective actions to ensure that applicable fatigue analyses remain within their allowable limits. The effects of aging due to fatigue will be managed by the AMP for the subsequent license renewal operating period in accordance with 10 CFR 54.21(c)(1)(iii). 

Program should be implemented before the subsequent period of extended operation 

Components 

Evaluated for CUFen

The effects of the water environment on component fatigue life will be addressed by assessing the impact of the water environment on the limiting component locations, using the positions described in Regulatory Guide 1.207, Revision 1. A limiting sample of critical 

components can be evaluated by applying environmental adjustment factors to the existing CUF analyses or by performing more refined calculations. The AMPs monitor and track the number of occurrences and severity of thermal and pressure transients, monitor water chemistry, and require corrective actions to ensure that the applicable fatigue analyses remain within their allowable limits. The effects of aging due to environmentally assisted fatigue will be managed by the AMPs for the subsequent license renewal operating period in accordance with 10 CFR 54.21(c)(1)(iii). 

Program should be implemented before the subsequent period of extended operation 

4.4-1 

1 4.4 Environmental Qualification (EQ) of Electric Equipment 

2 Review Responsibilities 

3 Primary—Branch responsible for electrical engineering 

4 Secondary—None 

5 4.4.1 Areas of Review 

6 The U.S. Nuclear Regulatory Commission (NRC) has established environmental qualification 

7 requirements in the Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix A, 

8 Criterion 4, and 10 CFR 50.49. Section 50.49 specifically requires each nuclear power plant 

9 licensee to establish a program to qualify certain electric equipment (not including equipment 

10 located in mild environments) so that such equipment, up to its end-of-life condition, will meet its 

11 performance specifications during and following design basis accidents under the most severe 

12 environmental conditions postulated at the equipment’s respective location (qualified life). Such 

13 conditions include, among others, conditions resulting from a design basis event such as a loss of 

14 coolant accident (LOCA), high-energy line break (HELBs), and post-LOCA environments. 

15 Electric equipment is qualified to perform its safety function in those harsh environments after 

16 the effects of inservice aging.  10 CFR 50.49 requires that the effects of significant aging 

17 mechanisms be addressed as part of environmental qualification.  Those components with a 

18 qualified life equal to or greater than the duration of the current operating term are covered by 

19 time-limited aging analyses (TLAAs). 

20 For equipment located in a harsh environment, the objective of Environmental Qualification (EQ) 

21 is to demonstrate with reasonable assurance that electric equipment important to safety, for 

22 which a qualified life has been established, can perform its safety function(s) without 

23 experiencing common cause failures before, during or after applicable design basis events. 

24 For equipment located in a mild environment (an environment that at no time would be 

25 significantly more severe than the environment occurring during normal operation, including 

26 anticipated operational occurrences—10 CFR 50.49), the demonstration that the equipment can 

27 meet its functional requirements during normal environmental conditions and anticipated 

28 operational occurrences in accordance with the plant’s design and licensing bases. Equipment 

29 important to safety located in a mild environment is not part of an EQ program according to 

30 10 CFR 50.49 [10 CFR 50.49(c)]. Documents that demonstrate that a component is qualified or 

31 designed for a mild environment include design/purchase specifications, seismic qualification 

32 reports, an evaluation or certificate of conformance as applicable. 

33 Some nuclear power plants have mechanical equipment that was qualified in accordance with 

34 the provisions of Criterion 4 of Appendix A to 10 CFR Part 50. If a plant has qualified 

35 mechanical equipment, it is typically documented in the plant’s master EQ list. If this qualified 

36 mechanical equipment requires a performance of a TLAA, it should be performed in accordance 

37 with the provisions of SRP-SLR Section 4.7, “Other Plant-Specific Time-Limited Aging 

38 Analyses.” If a TLAA of qualified mechanical equipment is necessary, usually it will involve 

39 assessments of the environmental effects on consumable components such as seals, gaskets, 

40 lubricants, fluids for hydraulic systems, or diaphragms. 
4.4-2 

1 4.4.1.1 Time-Limited Aging Analysis 

2 All operating plants must meet the requirements of 10 CFR 50.49 for certain important-to-safety 

3 electrical components. 10 CFR 50.49 defines the scope of components to be included, requires 

4 the preparation and maintenance of a list of in-scope components, and requires the preparation 

5 and maintenance of a qualification file that includes component performance specifications, 

6 electrical characteristics, and environmental conditions. 10 CFR 50.49(e)(5) contains 

7 provisions for aging that require, in part, consideration of all significant types of aging 

8 degradation that can affect component functional capability. 10 CFR 50.49(e) also requires 

9 component replacement or refurbishment prior to the end of designated life, unless additional 

10 life is established through reanalysis or ongoing qualification. 10 CFR 50.49(f) establishes four 

11 methods of demonstrating qualification for aging and accident conditions. 10 CFR 50.49(k) and 

12 (i) permit different qualification criteria to apply based on plant and component vintage. 

13 Supplemental environmental qualification regulatory guidance for compliance with these 

14 different qualification criteria is provided in NRC Regulatory Guide (RG) 1.89, Rev. 1, 

15 “Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear 

16 Power Plants” (Ref. 1), and the Division of Operating Reactors (DOR) Guidelines (Ref. 2), and 

17 NUREG–0588 (Ref. 3). The principal nuclear industry qualification standards for electric 

18 equipment are Institute of Electrical and Electronics Engineers (IEEE) STD 323-1971 (Ref. 4) 

19 and IEEE STD 323-1974 (Ref. 5). These standards contain explicit EQ considerations based 

20 on TLAAs. Compliance with 10 CFR 50.49 provides reasonable assurance that the component 

21 can perform its intended functions during and following accident conditions after experiencing 

22 the effects of inservice aging for applicable equipment. 

23 4.4.1.1.1 Division of Operating Reactors Guidelines 

24 The qualification of electric equipment that is subject to significant known degradation due to 

25 aging where a qualified life was previously required to be established in accordance with 

26 Section 5.2.4 of the DOR Guidelines is reviewed for the period of subsequent period of extended 

27 operation according to those requirements. If a qualified life was not previously established, the 

28 qualification is reviewed in accordance with Section 7 of the DOR Guidelines. 

29 4.4.1.1.2 NUREG–0588, Category II (IEEE STD 323-1971) 

30 The qualification of certain electric equipment important to safety for which qualification was 

31 required in accordance with NUREG–0588, Category II, is reviewed for conformance to those 

32 requirements for the subsequent period of extended operation to assess the validity of the 

33 extended qualification. These requirements include IEEE STD 382-1972 (Ref. 6) for valve 

34 operators and IEEE STD 334-1971 (Ref. 7). In addition, 10 CFR 50.49(L) has to be addressed 

35 for replacement equipment. 

36 4.4.1.1.3 NUREG–0588, Category I (IEEE STD 323-1974) 

37 The qualification of certain electric equipment important to safety for which qualification was 

38 required in accordance with NUREG–0588, Category I, is reviewed for conformance to those 

39 requirements for the subsequent period of extended operation to assess the validity of the 

40 extended qualification. 
4.4-3 

1 4.4.1.2 Generic Safety Issue 

2 Regulatory Issue Summary (RIS) 2003-09 was issued on May 2, 2003, (Ref. 8) to inform 

3 addressees of the results of the technical assessment of generic safety issue (GSI)-168, 

4 “Environmental Qualification of Electrical Equipment” (Ref. 9). This RIS requires no action on 

5 the part of the addressees. 

6 4.4.1.3 Final Safety Analysis Report Supplement 

7 The detailed information on the evaluation of TLAAs is contained in the subsequent license 

8 renewal application (SLRA). A summary description of the evaluation of TLAAs for the period of 

9 extended operation is contained in the applicant’s Final Safety Analysis Report (FSAR) 

10 supplement. The FSAR supplement is an area of review. 

11 4.4.2 Acceptance Criteria 

12 The acceptance criteria for the areas of review described in Subsection 4.4.1 of this review plan 

13 section delineate acceptable methods for meeting the requirements of the NRC’s regulations in 

14 10 CFR 54.21(c)(1). 

15 4.4.2.1 Time-Limited Aging Analysis 

16 For long-term operation, TLAAs are reviewed to determine continued acceptability of 

17 the analyzed component for the subsequent period of extended operation. The 

18 time-dependent parameter is reevaluated, analyzed or assumed to determine a value 

19 that applies to the subsequent period of extended operation. This new value of the 

20 time-dependent parameter is then used to reevaluate the analysis parameter, applicable to 

21 the subsequent period of extended operation. 

22 Pursuant to 10 CFR 54.21(c)(1)(i)–(iii), the TLAA is acceptable if it meets one of the 

23 following cases: 

24 (i) The analysis remains valid for the subsequent period of extended operation. The 

25 time-dependent parameter(s) for the subsequent period of extended operation 

26 does not exceed the time-dependent parameter value used in the existing 

27 EQ analysis. 

28 (ii) The analysis has been projected to the end of the subsequent period of extended 

29 operation and remains acceptable for the subsequent period of extended operation. 

30 The time-dependent parameter(s) is projected for the subsequent period of 

31 extended operation. The value of the time-dependent analysis parameter(s) 

32 remains bounded to the value used in the existing EQ analysis. 

33 (iii) The effects of aging on the intended function(s) will be adequately managed for the 

34 subsequent period of extended operation. 

35 The applicant manages the time-dependent parameter [using an aging management 

36 program (AMP) (e.g., GALL-SLR Report AMP X.E1, “SLR AMP X.E1 Environmental 

37 Qualification (EQ]” of Electric Components) to assure that the value of the analysis 

38 parameter continues to meet the EQ analysis value. 
4.4-4 

1 Specific acceptance criteria for EQ of certain electric equipment important to safety analyzed to 

2 Section 5.2.4 of the DOR Guidelines; NUREG–0588, Category II (Section 4); or NUREG–0588, 

3 Category I, depend on the applicant’s choice, that is, 10 CFR 54.21(c)(1)(i), (ii), or (iii), and are: 

4 4.4.2.1.1 10 CFR 54.21(c)(1)(i) 

5 The existing qualification is based on previous testing, analysis, or operating experience, or 

6 combinations thereof, that demonstrate that the equipment is qualified for the period of extended 

7 operation. For option (i), the aging evaluation existing at the time of the SLRA for the 

8 component remains valid for the subsequent period of extended operation, and no further 

9 evaluation is necessary. 

10 4.4.2.1.2 10 CFR 54.21(c)(1)(ii) 

11 Qualification of the equipment is extended for the subsequent period of extended operation by 

12 testing, analysis, or operating experience, or combinations thereof, in accordance with the CLB. 

13 For option (ii), a reanalysis of the aging evaluation is performed in order to project the 

14 qualification of the component through the subsequent period of extended operation. Important 

15 reanalysis attributes of an aging evaluation include analytical methods, data collection and 

16 reduction methods, underlying assumptions, acceptance criteria, and corrective actions if 

17 acceptance criteria are not met. These reanalysis attributes are discussed in Table 4.4-1. 

18 4.4.2.1.3 10 CFR 54.21(c)(1)(iii) 

19 In Chapter X of the Generic Aging Lessons Learned for Subsequent License Renewal 

20 (GALL-SLR) Report (Ref. 10), the NRC staff has evaluated the EQ program (10 CFR 50.49) and 

21 determined that it is an acceptable AMP to address EQ according to 10 CFR 54.21(c)(1)(iii). 

22 The GALL-SLR Report may be referenced in a SLRA and should be treated in the same 

23 manner as an approved topical report. However, the GALL-SLR Report contains one 

24 acceptable way and is not the only way to manage aging for SLR. 

25 In referencing the GALL-SLR Report, the applicant should indicate that the material referenced 

26 is applicable to the specific plant involved and should provide the information necessary to 

27 adopt the finding of program acceptability as described and evaluated in the report. The 

28 applicant should also verify that the approvals set forth in the GALL-SLR Report for the generic 

29 program apply to the applicant’s program. 

30 4.4.2.2 Final Safety Analysis Report Supplement 

31 The specific criterion for meeting 10 CFR 54.21(d) is: 

32 The summary description of the evaluation of TLAAs for the period of extended 

33 operation in the FSAR supplement is appropriate such that later changes can be 

34 controlled by 10 CFR 50.59. The description should contain information 

35 associated with the TLAA regarding the basis for determining that the applicant 

36 has made the demonstration required by 10 CFR 54.21(c)(1). 

37 
4.4-5 

1 4.4.3 Review Procedures 

2 For each area of review described in Subsection 4.4.1, the following review procedures should 

3 be followed: 

4 4.4.3.1 Time-Limited Aging Analysis 

5 For electric equipment qualified to the requirements of 10 CFR 50.49, the review procedures 

6 depend on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), which are: 

7 4.4.3.1.1 10 CFR 54.21(c)(1)(i) 

8 The documented results, test data, analyses, etc. of the previous qualification, which consisted 

9 of an appropriate combination of testing, analysis, and operating experience, are reviewed 

10 to confirm that the original qualified life remains valid for the subsequent period of extended 

11 operation. 

12 4.4.3.1.2 10 CFR 54.21(c)(1)(ii) 

13 The results of projecting the qualification to the end of the subsequent period of extended 

14 operation are reviewed. The qualification methods include testing, inspection, operating 

15 experience, reanalysis, ongoing qualification or combinations thereof. 

16 The reanalysis of an aging evaluation is normally performed to extend the qualification by 

17 reevaluating original attributes, assumptions and conservatisms for environmental conditions 

18 and other factors to identify excess conservatisms incorporated in the prior evaluation. 

19 Reanalysis of an aging evaluation to extend the qualification of electrical equipment is 

20 performed pursuant to 10 CFR 50.49(e) as part of an EQ program. While an electrical 

21 equipment life limiting condition may be due to thermal, radiation, or operational/testing and 

22 cyclic aging, the majority of electrical equipment aging limits are based on thermal conditions. 

23 Conservatism may exist in aging evaluation parameters, such as the assumed service 

24 conditions including temperature and radiation, loading, power, signal conditions, cycles, and 

25 application (e.g., de-energized versus energized), or the use of an unrealistically low 

26 activation energy. 

27 The reanalysis of an aging evaluation is performed according to the station’s quality assurance 

28 (QA) program requirements, which requires the verification of assumptions and conclusions 

29 including the maintenance of required margins and uncertainties. 

30 For reanalysis, the reviewer verifies that an applicant has completed its reanalysis, addressing 

31 attributes of analytical methods, data collection and reduction methods, underlying assumptions, 

32 acceptance criteria, and corrective actions if acceptance criteria are not met (see Table 4.4-1). 

33 The reviewer also verifies that the reanalysis has been completed in a timely manner prior to the 

34 end of qualified life. 

35 4.4.3.1.3 10 CFR 54.21(c)(1)(iii) 

36 The applicant may reference the GALL-SLR Report in its SLRA, as appropriate. The review 

37 should verify that the applicant has stated that the report is applicable to its plant with respect to 

38 its EQ program. The reviewer verifies that the applicant has identified the appropriate AMP as 

39 described and evaluated in the GALL-SLR Report. The reviewer also ensures that the applicant 
4.4-6 

1 has stated that its EQ program contains, and is consistent with, the same program elements 

2 that the NRC staff evaluated and relied upon in approving the corresponding generic AMP in the 

3 GALL-SLR Report. No further NRC staff evaluation is necessary. 

4 If the applicant does not reference the GALL-SLR Report in its renewal application, additional 

5 NRC staff evaluation is necessary to determine whether the applicant’s TLAA analysis and EQ 

6 AMP is acceptable for this area of review. 

7 4.4.3.2 Final Safety Analysis Report Supplement 

8 The reviewer verifies that the applicant has provided information to be included in the FSAR 

9 supplement that includes a summary description of the TLAA evaluation of the applicant’s EQ 

10 AMP including time dependent electric equipment. Table 4.4-2 contains examples of 

11 acceptable FSAR supplement information for this TLAA. The reviewer verifies that the applicant 

12 has provided a FSAR supplement with information consistent with that in Table 4.4-2 including 

13 plant-specific commitments, license conditions, enhancements or exceptions. 

14 As noted in Table 4.4-2, an applicant need not incorporate the implementation schedule into its 

15 FSAR. However, the reviewer should verify that the applicant has identified in the SLRA any 

16 future aging management activities, including commitments, license conditions, 

17 enhancements, and exceptions to be implemented prior to or during the subsequent period of 

18 extended operation. 

19 4.4.4 Evaluation of Findings 

20 The reviewer determines whether the applicant has provided information sufficient to satisfy the 

21 provisions of this section and whether the applicant’s evaluation supports conclusions of the 

22 applicant’s TLLA evaluation. Depending on the applicant’s selection, a review of the applicant’s 

23 10 CFR 54.21(c)(1)(i), (ii), or (iii) evaluation is to be included in the NRC staff’s Safety Evaluation 

24 Report. 

25 The NRC staff confirms that the FSAR supplement contains a sufficiently detailed summary 

26 description with key AMP attributes identified in the FSAR summary description. The NRC staff 

27 also confirms the FSAR summary provides a summary description of any commitments, license 

28 conditions, enhancements, or exceptions as appropriate. 

29 On the basis of its review, the NRC staff concludes that the applicant has 

30 provided an acceptable demonstration, pursuant to 10 CFR 54.2 (c)(1), that, for 

31 the environmental qualification of Electric Equipment TLAA, [choose which is 

32 appropriate] (i) the analyses remain valid for the subsequent period of extended 

33 operation, (ii) the analyses have been projected to the end of the subsequent 

34 period of extended operation, or (iii) the effects of aging on the intended 

35 function(s) will be adequately managed for the subsequent period of 

36 extended operation. 

37 4.4.5 Implementation 

38 Except in those cases in which the applicant proposes an alternative method for complying with 

39 specific portions of the NRC’s regulations, the method described herein will be used by the NRC 

40 staff in its evaluation of conformance with NRC regulations. 
4.4-7 

1 4.4.6 References 

2 1. NRC. Regulatory Guide 1.89, “Environmental Qualification of Certain Electric 

3 Equipment Important to Safety for Nuclear Power Plants.” Revision 1. Washington, DC: 

4 U.S. Nuclear Regulatory Commission. June 1984. 

5 2. NRC. “Guidelines for Evaluating Environmental Qualification of Class 1E Electrical 

6 Equipment in Operating Reactors.” DOR Guidelines. Washington, DC: U.S. Nuclear 

7 Regulatory Commission. November 1979. 

8 3. NRC. NUREG–0588, “Interim Staff Position on Environmental Qualification of Safety9 Related Equipment.” Washington, DC: U.S. Nuclear Regulatory Commission. 

10 July 1981. 

11 4. IEEE. Standard 323-1971, “IEEE Trial Use Standard; General Guide for Qualifying 

12 Class 1E Equipment for Nuclear Power Generating Stations.” New York City, New York: 

13 Institute of Electrical and Electronics Engineers. 

14 5. IEEE. Standard 323-1974, “IEEE Standard for Qualifying Class 1E Equipment for 

15 Nuclear Power Generating Stations.” New York City, New York: Institute of Electrical 

16 and Electronics Engineers. 

17 6. IEEE. Standard 382-1972, “Standard for Qualification of Actuators for Power Operated 

18 Valve Assemblies with Safety Related Functions for Nuclear Power Plants.” New York 

19 City, New York: Institute of Electrical and Electronics Engineers. 

20 7. IEEE. Standard 334-1971, “IEEE Standard for Type Tests of Continuous Duty Class 1E 

21 Motors for Nuclear Power Generating Stations.” New York City, New York: Institute of 

22 Electrical and Electronics Engineers. 

23 8. NRC. Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

24 Instrumentation and Control Cables.” Washington, DC: U.S. Nuclear Regulatory 

25 Commission. May 2, 2003. 

26 9. NRC. “Environmental Qualification of Low-Voltage Instrumentation and Control Cables.” 

27 Generic Safety Issue-168. Washington, DC: U.S. Nuclear Regulatory Commission. 

28 February 2001. 

29 11. CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, 

30 Washington, DC: U.S. Nuclear Regulatory Commission. 2009.

31 12. CFR 50.49, “Environmental Qualification of Electrical Equipment Important to Safety for 

32 Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2014.

33 13. NRC. Regulatory Guide 1.211, “Qualification of Safety-Related Cables and Field Splices 

34 for Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

35 April 2009. 
4.4-8 

1 14. NRC. Regulatory Guide 1.100, “Seismic Qualification of Electrical and Active 

2 Mechanical Equipment and Functional Qualification of Active Mechanical Equipment for 

3 Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 

4 September 2009. 

5 15. NRC. Regulatory Guide 1.218, “Condition-Monitoring Techniques for Electric Cables 

6 Used in Nuclear Power Plants.” Washington, DC: U.S. Nuclear Regulatory 

7 Commission. April 2012. 

8 16. IEEE, Standard 1205-2014, “IEEE Guide for Assessing, Monitoring, and Mitigating 

9 Aging Effects on Electrical Equipment Used in Nuclear Power Generating Stations and 

10 Other Nuclear Facilities.” New York City, New York: Institute of Electrical and 

11 Electronics Engineers.
4.4-9 

Table 4.4-1. Environmental Qualification Reanalysis Attributes 

Reanalysis Attributes Description 

Analytical methods The analytical models used in the reanalysis of an aging 

evaluation are the same as those previously applied during the 

prior evaluation. The Arrhenius methodology is an acceptable 

thermal model for performing a thermal aging evaluation. The 

analytical method used for a radiation aging evaluation is to 

demonstrate qualification for the total integrated dose (i.e., 

normal radiation dose for the projected installed life plus accident 

radiation dose). For SLR, one acceptable method of establishing 

the 80-year normal radiation dose is to multiply the 60-year 

normal radiation dose by 2.0 (i.e., 80 years/40 years). The result 

is added to the accident radiation dose to obtain the total 

integrated dose for the component. For aging effects attributed 

to cyclic aging, a similar approach may be used. Other models 

may be justified on a case-by case basis. 

Data collection and 

reduction methods 

The identification of excess conservatism in electrical equipment 

service conditions (for example, temperature, radiation, and 

cycles) used in the prior aging evaluation is the chief method 

used for a reanalysis. For example, temperature data and 

uncertainties used in an equipment EQ evaluation may be based 

on the anticipated plant design temperatures found to be 

conservative when compared to actual plant temperature data. 

When used, plant temperature data can be obtained in several 

ways, including monitors used for technical specification 

compliance; other installed monitors, measurements made by 

plant operators during rounds, or dedicated monitoring 

equipment for EQ. 

A representative number of temperature measurements over a 

sufficient period of time are evaluated to establish the 

temperatures used in an aging evaluation. Plant temperature 

data may be used in an aging evaluation in different ways, such 

as (a) directly applying the plant temperature data in the 

evaluation or (b) using the plant temperature data to 

demonstrate conservatism when using plant design 

temperatures for an evaluation. The methodology for 

environmental monitoring, data collection and the analysis of 

localized EQ equipment environmental data (including 

temperature and radiation) used in the reanalysis is justified in 

the record of the reanalysis qualification report. 

Environmental monitoring data used in the analysis that is 

collected one time, or is of limited duration, is justified with 

respect to the applicability of such data to the reanalysis. Any 

changes to material activation energy values included as part of 

a reanalysis are justified by the applicant on a plant-specific 

basis. Similar methods of identifying excess conservatism in the 

equipment service condition evaluation can be used for radiation 

and cyclic aging. 
4.4-10 

Table 4.4-1. Environmental Qualification Reanalysis Attributes 

Reanalysis Attributes Description 

Underlying assumptions EQ equipment aging evaluations contain conservatism to 

account for most environmental changes occurring due to plant 

modifications and events. A reanalysis demonstrates that 

adequate margin is maintained consistent with the original 

analysis in accordance with 10 CFR 50.59 requiring certain 

margins and accounting for the unquantified uncertainties 

established in the EQ aging evaluation of the equipment. A 

reanalysis that utilizes initial qualification conservatisms and/or 

in-service environmental conditions (e.g., actual temperature 

and radiation conditions) are part of an EQ program. 

Adverse localized environments are identified during periodic 

inspections, or by operational or maintenance activities that affect 

the operating environment of an environmentally qualified 

component, the affected component is evaluated and appropriate 

corrective actions are taken, which may include changes to the 

qualification bases and conclusions (e.g., changes to 

qualified life). 

Acceptance criteria and 

corrective actions 

The reanalysis of an aging evaluation is used to extend the 

environmental qualification of a component. If the qualification 

cannot be extended by reanalysis, the component must be 

refurbished, replaced, or requalified prior to exceeding the 

current qualified life. A reanalysis should be performed in a 

timely manner (such that sufficient time is available to refurbish, 

replace, or requalify the component if the reanalysis is 

unfavorable). A modification to qualified life either by reanalysis 

or ongoing qualification must demonstrate that adequate margin 

is maintained consistent with the original analysis including 

unquantified uncertainties established in the original EQ 

equipment aging valuation. 

Ongoing Qualification As an alternative to reanalysis when assessed margins, 

conservatisms, or assumptions do not support reanalysis (e.g., 

extending qualified life) of an EQ component, the use of ongoing qualification techniques including condition monitoring or 

condition based methodologies may be implemented as a 

means to provide reasonable assurance that an equipment 

environmental qualification is maintained for the subsequent 

period of extended operation. 

On-going qualification of electric equipment important to safety 

subject to the requirements of 10 CFR 50.49 involves the 

inspection, observation, measurement, or trending of one or 

more indicators, which can be correlated to the condition or 

functional performance of the EQ equipment. On-going 

Qualification techniques, including condition based monitoring, 

provide information that may be used in the determination a 

component’s ability to perform its safety function and the 
4.4-11 

Table 4.4-1. Environmental Qualification Reanalysis Attributes 

Reanalysis Attributes Description 

components remaining qualified life for the subsequent period of 

extended operation. 

On-going qualification techniques for EQ equipment include, as 

applicable, periodic testing, inspections, mitigation, sampling 

(e.g., subsequent EQ qualification testing of inservice or 

representative EQ equipment with established acceptance 

criteria and corrective actions (e.g., mitigation, replacement or 

refurbishment) consistent with endorsed standards and 

regulatory guidance. 
4.4-12 

Table 4.4-2. Examples of FSAR Supplement for Environmental Qualification Electric Equipment TLAA Evaluation 10 CFR 54.21(c)(1)(i) Example

TLAA Description of Evaluation Implementation

Schedule*

4.4 Environmental 

qualification of electric equipment 

The original environmental qualification qualified life has been shown to remain valid for the period of extended operation. [Plant specific identification and summary descriptions of commitments, license conditions, enhancements or exceptions are also described as applicable] 

10 CFR 54.21(c)(1)(ii) Example 

TLAA Description of Evaluation Implementation

Schedule*

4.4 Environmental 

qualification of electric equipment 

The environmental qualification has been projected to the end of the period of extended operation. [The summary report addresses the key reanalysis attributes of analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions]. [Plant specific identification and summary descriptions of commitments, license conditions, enhancements or exceptions are also described as applicable] 

Completed 

 10 CFR 54.21(c)(1)(iii) Example

TLAA Description of Evaluation Implementation 

Schedule 

4.4 Environmental 

qualification of electric equipment 

The applicant’s environmental qualification process, in accordance with 10 CFR 50.49, will adequately manage aging of environmental qualification equipment for the period of extended operation because equipment will be replaced prior to reaching the end of its qualified life. [The summary report addresses the key reanalysis attributes of methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions.] 

Existing program 
4.4-13 

Table 4.4-2. Examples of FSAR Supplement for Environmental Qualification Electric Equipment TLAA Evaluation

[The applicant states that its environmental qualification program contains the same elements evaluated in the GALL-SLR Report.] [Plant specific identification and summary descriptions of commitments, license conditions, enhancements or exceptions are also described as applicable] 

4.5-1 

1 4.5 Concrete Containment Unbonded Tendon Prestress Analysis 

2 Review Responsibilities 

3 Primary—Branch responsible for structural engineering 

4 Secondary—Branch responsible for structural engineering 

5 4.5.1 Areas of Review 

6 The prestressing tendons in prestressed concrete containments undergo losses in prestressing 

7 forces with time due to creep and shrinkage of concrete and relaxation of the prestressing steel. 

8 During the design phase, engineers estimated these losses to the end of the prestressed 

9 containment operating life, normally 40 years. Operating experiences with the trend of 

10 prestressing forces indicate the prestressing tendons lose their prestressing forces at a rate 

11 higher than predicted due to sustained high temperature. In addition, loss of prestress or 

12 reduction in tendon force can occur due to breakage of tendon wires or improper anchorages. 

13 Stress corrosion cracking (SCC) in individual tendons can also occur and contribute to the loss 

14 of tendon prestress if there is a susceptible material and environment combination. Moreover, 

15 consideration should be given to an increased tendon relaxation when replacing existing in service 

16 tendons with new. Thus, it is necessary to ensure that the applicant addresses existing Time 

17 Limited Aging Analyses (TLAAs) for the subsequent period of extended operation. Plant specific 

18 TLAAs regarding loss of prestress [e.g., predicted tendon prestress force lower limit–predicted 

19 lower limit (PLL), bonded tendons] are addressed and reviewed in Section 4.7, “Other 

20 Plant-Specific Time-Limited Aging Analyses.” 

21 The adequacy of the prestressing forces in prestressed concrete containments is reviewed for 

22 the subsequent period of extended operation. 

23 4.5.2 Acceptance Criteria 

24 The acceptance criteria for the area of review described in Subsection 4.5.1 delineate 

25 acceptable methods for meeting the requirements of the U.S. Nuclear Regulatory Commission 

26 (NRC) regulations in Title 10 of the Code of Federal Regulations (10 CFR) 54.21(c)(1). 

27 4.5.2.1 Time-Limited Aging Analysis 

28 Pursuant to 10 CFR 54.21(c)(1)(i) - (iii), an applicant must demonstrate one of the following: 

29 (i) The analyses remain valid for the subsequent period of extended operation; 

30 (ii) The analyses have been projected to the end of the subsequent period of extended 

31 operation; or 

32 (iii) The effects of aging on the intended function(s) will be adequately managed for the 

33 subsequent period of extended operation. 

34 4.5.2.1.1 10 CFR 54.21(c)(1)(i) 

35 The existing prestressing force evaluation remains valid because (a) losses of the prestressing 

36 force are less than the predicted losses, as evidenced from the trend lines constructed from the 
4.5-2 

1 recent inspection, (b) the period of evaluation covers the subsequent period of extended 

2 operation, and (c) the trend lines of the measured prestressing forces remain above the minimum 

3 required prestress force specified at anchorages for each group of tendons for the subsequent 

4 period of extended operation.

5 4.5.2.1.2 10 CFR 54.21(c)(1)(ii) 

6 The prediction line of prestressing forces for each group of tendons initially developed for 

7 40 years of operation should be extended to 80 years. The applicant demonstrates through 

8 analysis the unbonded tendon prestressed concrete containment design adequacy remains 

9 valid and that the trend lines of the measured prestressing forces will stay above the design 

10 Minimum Required Value (MRV) in the current licensing basis (CLB) for each group of tendons 

11 during the subsequent period of extended operation.

12 4.5.2.1.3 10 CFR 54.21(c)(1)(iii) 

13 In Chapter X of the Generic Aging Lessons Learned for Subsequent License Renewal 

14 (GALL-SLR) Report, the NRC staff evaluated a program that assesses the concrete 

15 containment tendon prestressing forces [aging management program (AMP) X.S1, “Concrete 

16 Containment Unbonded Tendon Prestress”], and has determined that it is an acceptable AMP to 

17 address concrete containment tendon prestress according to 10 CFR 54.21(c)(1)(iii), except for 

18 operating experience. Further evaluation is recommended of the applicant’s operating 

19 experience related to the containment prestress force. However, the GALL-SLR Report 

20 contains one acceptable way and not the only way to manage aging. The GALL-SLR report 

21 may be referenced in a subsequent license renewal application (SLRA), and is treated in the 

22 same manner as an approved topical report. 

23 In referencing the GALL-SLR report, an applicant indicates that the material referenced is 

24 applicable to the specific plant involved and should provide the information necessary to adopt 

25 the finding of program acceptability as described and evaluated in the report. An applicant also 

26 verifies that the approvals set forth in the GALL-SLR report for the generic program apply to the 

27 applicant’s program. 

28 4.5.2.2 Final Safety Analysis Report Supplement 

29 The specific criterion for meeting 10 CFR 54.21(d) is: 

30 The summary description of the evaluation of TLAAs for the subsequent period of extended 

31 operation in the Final Safety Analysis Report (FSAR) supplement is appropriate such that later 

32 changes can be controlled by 10 CFR 50.59. The description must contain information 

33 associated with the TLAAs regarding the basis for determining that the applicant has made the 

34 demonstration required by 10 CFR 54.21(c)(1). 
4.5-3 

1 4.5.3 Review Procedures 

2 For each area of review described in Subsection 4.5.1, the following review procedures should 

3 be followed: 

4 4.5.3.1 Time-Limited Aging Analysis 

5 For a concrete containment prestressing tendon system, the review procedures, depending on 

6 the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), are: 

7 4.5.3.1.1 10 CFR 54.21(c)(1)(i) 

8 The results of a recent inspection to measure the amount of prestress loss are reviewed to 

9 ensure that the reduction of prestressing force is less than the predicted loss in the existing 

10 analysis. The reviewer verifies that the trend line of the measured prestressing force, when 

11 plotted on the predicted prestressing force curve, shows that the existing analysis remains valid 

12 for the subsequent period of extended operation. 

13 4.5.3.1.2 10 CFR 54.21(c)(1)(ii) 

14 The reviewer reviews the trend lines of the measured prestressing forces to ensure that 

15 individual tendon lift-off forces (rather than average lift-off forces of the sampled tendon group) 

16 are considered in the regression analysis for the subsequent period of extended operation, as 

17 discussed in Information Notice (IN) 99-10, “Degradation of Prestressing Tendon Systems in 

18 Prestressed Concrete Containments.” The reviewer then verifies that the trend lines will stay 

19 above the minimum required prestressing forces for each group of tendons during the 

20 subsequent period of extended operation so that the design adequacy is maintained in the 

21 subsequent period of extended operation.

22 4.5.3.1.3 10 CFR 54.21(c)(1)(iii) 

23 An applicant may reference the GALL-SLR Report in its SLRA, as appropriate. The reviewer 

24 verifies that the applicant has stated that the report is applicable to its plant with respect to its 

25 program that assesses the concrete containment tendon prestressing forces. The reviewer 

26 verifies that the applicant has identified the appropriate program (i.e., GALL-SLR Report 

27 AMP X.S1) as described and evaluated in the GALL-SLR Report. The reviewer also ensures 

28 that the applicant has stated that its program contains the same program elements that the 

29 NRC staff evaluated and relied upon in approving the corresponding generic program in the 

30 GALL-SLR Report. 

31 Further evaluation is recommended of the applicant’s operating experience related to the 

32 containment prestress force. The applicant’s program should incorporate the relevant 

33 operating experience that occurred at the applicant’s plant as well as at other plants. The 

34 applicant considers applicable portions of the experience with prestressing systems described 

35 in IN 99-10. Tendon operating experience could vary among plants with prestressed 

36 concrete containments. The difference could be due to the prestressing system design 

37 (for example, button-heads, wedge or swaged anchorages), environment, or type of reactor 

38 [pressurized water reactor (PWR) or boiling water reactor (BWR)]. The reviewer reviews the 

39 applicant’s program to verify that the applicant has adequately considered plant-specific 

40 operating experience. 
4.5-4 

1 If the applicant does not reference the GALL-SLR Report in its SLRA, additional NRC staff 

2 evaluation is necessary to determine whether the applicant’s program is acceptable for this area 

3 of review. The reviewer uses the guidance provided in Branch Technical Position (BTP) 

4 RLSB-1 of this Standard Review Plan for Review of Subsequent License Renewal Applications 

5 for Nuclear Power Plants (SRP-SLR) to ensure that loss of prestress in the concrete 

6 containment prestressing tendons is adequately managed so that trend lines will remain above 

7 the minimum required prestressing forces for each group of tendons for the subsequent period 

8 of extended operation. 

9 4.5.3.2 Final Safety Analysis Report Supplement 

10 The reviewer verifies that the applicant has provided information, to be included in the FSAR 

11 supplement, that includes a summary description of the evaluation of the tendon prestress 

12 TLAA. Table 4.5-1 contains examples of acceptable FSAR supplement information for this 

13 TLAA. The reviewer verifies that the applicant has provided an FSAR supplement with 

14 information equivalent to that in Table 4.5-1. 

15 The NRC staff expects to impose a license condition on any renewed license to require the 

16 applicant to update its FSAR to include this FSAR supplement at the next update required 

17 pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

18 complete, the applicant may make changes to the programs described in its FSAR supplement 

19 without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

20 the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the FSAR 

21 supplement before the license is renewed, no condition will be necessary. 

22 As noted in Table 4.5-1, an applicant need not incorporate the implementation schedule into its 

23 FSAR. However, the reviewer should verify that the applicant has identified and committed in 

24 the SLRA to any future aging management activities, including enhancements and 

25 commitments to be completed before the subsequent period of extended operation. The NRC 

26 staff expects to impose a license condition on any renewed license to ensure that the applicant 

27 will complete these activities no later than the committed date. 

28 4.5.4 Evaluation Findings 

29 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

30 provisions of Section 4.5 and whether the NRC staff’s evaluation supports conclusions of the 

31 following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

32 included in the Safety Evaluation Report: 

33 On the basis of its review, as discussed above, the NRC staff concludes that the 

34 applicant has provided an acceptable demonstration, pursuant to 

35 10 CFR 54.21(c)(1), that, for the concrete containment tendon prestress TLAA, 

36 [choose which is appropriate] (i) the analyses remain valid for the subsequent 

37 period of extended operation, (ii) the analyses have been projected to the end of 

38 the subsequent period of extended operation, or (iii) the effects of aging on the 

39 intended function(s) will be adequately managed for the subsequent period of 

40 extended operation. The NRC staff also concludes that the FSAR supplement 

41 contains an appropriate description of the concrete containment tendon prestress 

42 TLAA evaluation for the subsequent period of extended operation as reflected in 

43 the license condition. 
4.5-5 

1 4.5.5 Implementation 

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

3 method described herein will be used by the NRC staff in its evaluation of conformance with 

4 NRC regulations. 

5 4.5.6 References 

6 1. NRC. Regulatory Guide 1.35.1, “Determining Prestressing Forces for Inspection of 

7 Prestressed Concrete Containments.” Washington, DC: U.S. Nuclear Regulatory 

8 Commission. ML003740040. July 1990. 

9 2. NRC. Information Notice 99-10, “Degradation of Prestressing Tendon Systems in 

10 Prestressed Concrete Containments.” ML031500244. Washington, DC: U.S. Nuclear 

11 Regulatory Commission. April 1999. 
4.5-6 

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

Prestress TLAA Evaluation

10 CFR 54.21(c)(1)(i) Example

TLAA Description of Evaluation

Implementation 

Schedule* 

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart compressive 

forces in the prestressed concrete containments to resist 

the internal pressure inside the containment that would be 

generated in the event of a loss of coolant accident 

(LOCA). The prestressing forces generated by the tendons

diminish over time due to losses in prestressing forces in 

the tendons and in the surrounding concrete. The 

prestressing force review and evaluation has been 

completed and determined to remain valid to the end of the 

subsequent period of extended operation, and the trend 

lines of the measured prestressing forces will stay above 

the minimum required prestressing forces for each group of 

tendons to the end of this period. 

Completed 

10 CFR 54.21(c)(1)(ii) Example

TLAA Description of Evaluation

Implementation 

Schedule*

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart compressive 

forces in the prestressed concrete containments to resist 

the internal pressure inside the containment that would be 

generated in the event of a LOCA. The prestressing 

forces generated by the tendons diminish over time due to 

losses in prestressing forces in the tendons and in the 

surrounding concrete. The prestressing force analysis and 

evaluation has been completed and determined to remain 

within allowable limits to the end of the subsequent period 

of extended operation, and the trend lines of the measured 

pre-stressing forces will stay above the minimum required 

prestressing forces for each group of tendons to the end of 

this period. 

Completed 

10 CFR 54.21(c)(1)(iii) Example

TLAA Description of Evaluation Implementation 

Schedule* 

Concrete 

Containment 

Tendon 

Prestress 

The prestressing tendons are used to impart 

compressive forces in the prestressed concrete 

containments to resist the internal pressure inside the 

containment that would be generated in the event of a 

LOCA. The prestressing forces generated by the 

tendons diminish over time due to losses of prestressing 

forces in the tendons and in the surrounding concrete. 

The [identify the AMP] developed to monitor the 

prestressing forces will ensure that, during each 

inspection, the trend lines of the measured prestressing 

forces show that they meet the requirements of the 

ASME Code, Section XI, Subsection IWL, as 

incorporated by reference in 10 CFR 50.55a and 

Program should 

be implemented 

before the 

subsequent 

period of 

extended 

operation. 
4.5-7 

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

Prestress TLAA Evaluation

supplemented. If the trend lines cross the PLLs, 

corrective actions should be taken. The program 

incorporates plant-specific and industry operating 

experience. 

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

that the applicant has identified and committed in the license renewal application to any future aging management 

activities to be completed before the subsequent period of extended operation. The staff expects to impose a 

license condition on any renewed license to ensure that the applicant will complete these activities no later than the 

committed date. 

4.6-1 

1 4.6 Containment Liner Plate, Metal Containments, and Penetrations 

2 Fatigue Analysis 

3 Review Responsibilities 

4 Primary—Branch responsible for structural engineering 

5 Secondary—Branch responsible for mechanical engineering 

6 4.6.1 Areas of Review 

7 This section addresses fatigue analyses for containment metal liner plates, metal containments 

8 [including boiling water reactor (BWR) containment suppression chamber and the vent system), 

9 and penetrations (including personnel airlocks, equipment hatches, sleeves, dissimilar metal 

10 welds, and bellows]. 

11 The interior surface of a concrete containment structure is lined with thin metallic plates to 

12 provide a leak-tight barrier against the uncontrolled release of radioactivity to the environment, 

13 as required by Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix J. The 

14 thickness of the liner plates is generally between 1/4-in [6.2 mm] and 3/8-in [9.5 mm]. The liner 

15 plates are attached to the concrete containment wall by stud anchors or structural rolled shapes 

16 or both. The design process assumes that the liner plates do not carry loads. However, 

17 imposed loads or conditions (e.g., dead, seismic, thermal, internal pressure, creep and 

18 shrinkage) induce cyclic stresses in the liner plates. Thus, under design-basis conditions, the 

19 liner plates could experience cyclic strains. Some plants may have metal containments instead 

20 of concrete containments with liner plates. The metal containments are designed to carry dead 

21 loads and seismic loads in addition to the internal pressure and temperature loads. For BWR 

22 Mark I metal containments, the containment suppression pool torus chamber (wetwell) and the 

23 vent system are designed or evaluated for hydrodynamic loads associated with actuation of 

24 safety relief valves and the discharge into the suppression pool chamber. 

25 Fatigue of the containment liner plates or metal containments may be considered in the design 

26 based on an assumed number of occurrences and severities of cyclic loads for the current 

27 operating term. The cyclic loads include reactor building interior temperature variations during 

28 heatups and cooldowns of the reactor coolant system, loss of coolant accident (LOCA) as 

29 applicable, annual outdoor temperature variations, thermal loads due to the high energy 

30 containment penetration piping lines (such as steam and feedwater lines), seismic loads, and 

31 pressurization due to periodic Type A integrated leak rate tests. The BWR containment 

32 suppression pool chamber and the vent system are designed or evaluated for the hydrodynamic 

33 cyclic loads as described in Section 6.2.1.1.C, “Pressure-Suppression Type BWR 

34 Containments,” of NUREG–0800, “Standard Review Plan.” 

35 Electrical penetration assemblies are usually sealed canisters penetrating the containment liner 

36 plate or metal containment barrier such that a pressure boundary between the inboard and 

37 outboard sides of the penetration exists while maintaining electrical continuity through the 

38 device. Mechanical penetrations include piping penetrations, access penetrations, drywell 

39 head, and fuel transfer tubes. High energy piping penetrations and the fuel transfer tubes in 

40 some plants are equipped with stainless steel (SS) bellow assemblies. These penetrations 

41 accommodate loads from relative movements between the containment wall (including the liner) 

42 and the adjoining structures, and from Type B, local leak rate tests. The penetrations have 

43 sleeves (up to 3 m [10 ft] in length, with a 5- to 8-cm [2- to 3-inch] annulus around the piping) to 
4.6-2 

1 penetrate the concrete containment wall and allow movement of the piping system. Dissimilar 

2 metal welds connect the piping penetrations to the bellows or SS plates to provide essentially 

3 leak-tight penetrations. Historical maintenance records, industry operating experience, and 

4 aging mechanisms that include degradation due to fatigue and their effects on electrical and 

5 mechanical penetrations, are discussed in Electric Power Research Institute (EPRI) Report 

6 “Aging Management Guideline for Commercial Nuclear Power Plants Electrical and 

7 Mechanical Penetrations.” 

8 The containment metal liner plates, metal containments (including BWR containment 

9 suppression chamber and the vent system), and penetrations (including personnel airlocks, 

10 equipment hatches, sleeves, dissimilar metal welds, and bellows), may be designed in 

11 accordance with requirements of Section III of the American Society of Mechanical Engineers 

(ASME) Boiler and Pressure Vessel Code1 12 . If a plant’s code of record requires a fatigue 

13 parameter evaluation (fatigue analysis or fatigue waiver), then this analysis may be a 

14 time-limited aging analysis (TLAA) and should be evaluated in accordance with 

15 10 CFR 54.21(c)(1) for the subsequent license renewal (SLR) period. 

16 The adequacy of the fatigue parameter evaluations of the containment liner plates, metal 

17 containments, and penetrations is reviewed in this section for the subsequent period of 

18 extended operation. The number of cyclic load occurrences assumed in the fatigue parameter 

19 evaluations should be clearly identified in Section 4.6 of the applicant’s subsequent license 

20 renewal application (SLRA). The fatigue parameter evaluations of the pressure boundary of 

21 process piping are reviewed separately following the guidance in Standard Review Plan for 

22 Review of Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) 

23 Section 4.3, “Metal Fatigue.” 

24 4.6.1.1 Time-Limited Aging Analysis (Fatigue Parameter Evaluations) 

25 The ASME Code contains explicit requirements for fatigue parameter evaluations 

26 (fatigue analyses or fatigue waivers), which are TLAAs. Specific requirements are contained in 

27 the design code of reference for each plant. The severities and the numbers of cycles of actual 

28 loadings for each cyclic load assumed in the underlying analyses should be verified against the 

29 numbers and severities of the actual loads projected for the subsequent period of extended 

30 operation. Monitoring of cyclic loading is accomplished through a TLAA aging management 

31 program (AMP) consistent with the Generic Aging Lessons Learned for Subsequent License 

32 Renewal (GALL-SLR) Report, X.M1 “Cyclic Load Monitoring,” or through a site-specific AMP 

33 consistent with the guidance provided in the SRP-SLR, Appendix A.1, “Branch Technical 

34 Position, Aging Management Review—Generic.” 

35 4.6.1.1.1 Fatigue Analyses (ASME Section III, MC or Class 1) 

36 ASME, Boiler and Pressure Vessel (B&PV) Code, Section III, Division 2, “Code for Concrete 

37 Containments, Rules for Construction of Nuclear Facility Components,” and ASME B&PV Code, 

38 Section III, Division 1, “Subsection NE, Class MC Components, Rules for Construction of 

 

1

GALL-SLR Report Chapter 1, Table 1, identifies the ASME Code Section XI editions and addenda that are 

acceptable to use of AMPs. 
4.6-3 

1 Nuclear Facility Components,” require a fatigue analysis for liner plates, metal containments, 

2 and penetrations that considers all cyclic loads based on the anticipated number of cycles. 

3 Containment components also may be designed to ASME Section III Class 1 requirements. A 

4 Section III, MC or Class 1 fatigue analysis requires the calculation of the cumulative usage 

5 factor (CUF) based on the fatigue properties of the materials and the expected fatigue service of 

6 the component. The ASME code limits the CUF to a value less than or equal to one for 

7 acceptable fatigue design. The fatigue resistance of the liner plates or metal containments, and 

8 penetrations during the subsequent period of extended operation is an area of review. 

9 Other evaluations also contain metal fatigue analysis requirements based on a CUF calculation, 

10 such as metal bellows designed to ASME NC-3649.4(e)(3) Titles or NE-3366.2(e)(3) standards. 

11 4.6.1.1.2 Fatigue Waiver Evaluations 

12 The current licensing basis (CLB) may include fatigue waiver evaluations that preclude the need 

13 for performing CUF analyses of structural components. The American Society of Mechanical 

14 Engineers (ASME) Code Section III rules for performing fatigue waiver evaluations for structural 

15 components are analogous to those in the Code for performing fatigue waiver evaluations of 

16 mechanical components. ASME Code NE-3131(d) Titles (1974 editions or later) rules out 

17 consideration for earthquake transients unless they impact designated liner locations 

18 recognized in the specifications. ASME Code NE-3222.4(d) “Analysis for Cyclic Operations, 

19 Vessels Not Requiring Analysis for Cyclic Operation,” provides for a waiver from fatigue analysis 

20 when certain cyclic loading criteria are met. 

21 4.6.1.2 Final Safety Analysis Report Supplement 

22 The SLRA contains TLAA information for containment liner plates, metal containments, and 

23 penetrations. A summary description of the evaluation of containment liner plates, metal 

24 containments, and penetrations TLAAs for the subsequent period of extended operation is also 

25 contained in the applicant’s proposed final safety analysis report (FSAR) supplement. The 

26 FSAR supplement is an area of review. 

27 4.6.2 Acceptance Criteria 

28 The acceptance criteria for the areas of review described in Subsection 4.6.1 delineate 

29 acceptable methods for meeting the requirements of the U.S. Nuclear Regulatory Commission 

30 (NRC) regulations in 10 CFR 54.21(c)(1). 

31 4.6.2.1 Time-Limited Aging Analysis 

32 In some instances, the applicant may identify activities to be performed to verify the assumption 

33 bases of the fatigue parameter evaluations, the fatigue analyses, or the fatigue waiver 

34 evaluations. Evaluations of those activities are provided by the applicant. The reviewer assures 

35 that the applicant’s activities are sufficient to confirm the calculation assumptions for the 

36 SLR period. 

37 Pursuant to 10 CFR 54.21(c)(1), an applicant must demonstrate one of the following: 

38 (i) The analyses remain valid for the subsequent period of extended operation; 
4.6-4 

1 (ii) The analyses have been projected to the end of the subsequent period of extended 

2 operation; or 

3 (iii) The effects of aging on the intended function(s) will be adequately managed for 

4 the subsequent period of extended operation. 

5 Specific acceptance criteria for fatigue of containment liner plates, metal containments, and 

6 penetrations are provided in the following subsections. 

7 4.6.2.1.1 Fatigue Parameter Evaluations 

8 For containment liner plates, metal containments, and penetrations that have fatigue parameter 

9 evaluations, the acceptance criteria are provided in the following subsections depending on the 

10 applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). This section applies to the evaluations 

11 identified in Sections 4.6.1.1.1 and 4.6.1.1.2. 

12 4.6.2.1.1.1 10 CFR 54.21(c)(1)(i) 

13 The fatigue parameter evaluations remain valid because the numbers of occurrences and 

14 severities of assumed cyclic loads are not projected to be exceeded during the subsequent 

15 period of extended operation. 

16 4.6.2.1.1.2 10 CFR 54.21(c)(1)(ii) 

17 The fatigue parameter evaluations have been reevaluated based on revised numbers of 

18 occurrences and severities of assumed cyclic loads for the subsequent period of extended 

19 operation and have been shown to remain within the allowed limits. 

20 4.6.2.1.1.3 10 CFR 54.21(c)(1)(iii) 

21 The applicant proposes an AMP as the basis for demonstrating that the effect or effects of aging 

22 on the intended function(s) of the structure(s) or component(s) in the fatigue parameter 

23 evaluations will be adequately managed during the subsequent period of extended operation. 

24 GALL-SLR Report AMP X.M1 provides one method that may be used to demonstrate 

25 compliance with the requirement in 10 CFR 54.21(c)(1)(iii). 

26 An applicant may also propose another AMP to demonstrate compliance with the requirement in 

27 10 CFR 54.21(c)(1)(iii). If the basis for aging management is a plant-specific AMP, the AMP 

28 should be defined in terms of the 10 program elements defined in the SRP-SLR, Appendix A.1. 

29 If an inspection program is proposed as the basis for aging management, the AMP implements 

30 inspections of the component(s) or structure(s) in the evaluation. The AMP justifies the 

31 inspection methods and frequencies that are applicable to the component(s) or structure(s), 

32 such that the TLAA will meet the requirement of 10 CFR 54.21(c)(1)(iii). 

33 Consistent with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii), an AMP is proposed to 

34 accept the TLAA in accordance with 10 CFR 54.21(c)(1)(iii) and to manage the effects of 

35 cumulative fatigue damage or fatigue-induced cracking on the intended functions of the 

36 components during the subsequent period of extended operation. GALL-SLR Report 

37 AMP XI.M1 provides one AMP that may be used as the basis for accepting the fatigue 

38 parameter evaluation in accordance with 10 CFR 54.21(c)(1)(iii). However, other Generic Aging 
4.6-5 

1 Lessons Learned (GALL) AMPs or plant-specific AMPs or activities may be used to accept the 

2 TLAA in accordance 10 CFR 54.21(c)(1)(iii) if appropriately justified in the SLRA. 

3 4.6.2.2 Final Safety Analysis Report Supplement 

4 The summary description of the evaluation of TLAAs for the subsequent period of extended 

5 operation in the FSAR supplement is appropriate such that later changes can be controlled by 

6 10 CFR 50.59. The description should contain information associated with the TLAAs regarding 

7 the basis for determining that the applicant has made the demonstration required by 

8 10 CFR 54.21(c)(1). 

9 4.6.3 Review Procedures 

10 For each area of review described in Subsection 4.6.1, the review procedures in the following 

11 subsections should be used. 

12 4.6.3.1 Time-Limited Aging Analysis 

13 4.6.3.1.1 Fatigue Parameter Evaluations 

14 For containment liner plates, metal containments, and penetrations with fatigue parameter 

15 evaluations, the review procedures are provided in the following subsections depending on the 

16 applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

17 4.6.3.1.1.1 10 CFR 54.21(c)(1)(i) 

18 The projected number of occurrences and severities of cyclic loadings at the end of the 

19 subsequent period of extended operation is compared to the number of occurrences and 

20 severities of cyclic loadings used in the existing fatigue parameter evaluations. The comparison 

21 confirms that the number of occurrences and severities of cyclic loadings in the existing fatigue 

22 parameter evaluations will not be exceeded during the subsequent period of extended 

23 operation. 

24 4.6.3.1.1.2 10 CFR 54.21(c)(1)(ii) 

25 The revised number of occurrences and severities of cyclic loadings projected to the end of the 

26 subsequent period of extended operation is reevaluated. The revised fatigue parameter 

27 evaluations based on the projected number of occurrences and severities of cyclic loads are 

28 reviewed to ensure that the calculated fatigue parameters remain less than the allowed values 

29 at the end of the subsequent period of extended operation. 

30 If applicable, the code of record is used for the revised fatigue parameter evaluations, or the 

31 applicant may update to a later code edition pursuant to 10 CFR 50.55a. In the latter case, the 

32 reviewer verifies that the requirements in 10 CFR 50.55a are met. 

33 4.6.3.1.1.3 10 CFR 54.21(c)(1)(iii) 

34 Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant proposes an AMP or aging management 

35 activities as the basis for demonstrating that the effect or effects of aging on the intended 

36 function(s) of the structure(s) or component(s) in the fatigue parameter evaluation will be 

37 adequately managed during the subsequent period of extended operation. If an AMP 
4.6-6 

1 corresponding to GALL-SLR Report AMP X.M1 is used as the basis for managing cumulative 

2 fatigue damage or cracking due to fatigue or cyclical loading in the structure(s) or component(s), 

3 the reviewer reviews the applicant’s AMP against the program elements defined in GALL-SLR 

4 Report AMP X.M1. 

5 An applicant also has the option of proposing another GALL-based AMP, plant-specific AMP, or 

6 plant-specific activities, or combination thereof, to demonstrate compliance with the requirement 

7 in 10 CFR 54.21(c)(1)(iii). If another GALL-based AMP is proposed as the basis for aging 

8 management, the reviewer reviews the applicant’s AMP against the program element criteria 

9 defined in the applicable AMP section in Appendix A of the GALL-SLR Report. If the basis for 

10 aging management is a plant-specific AMP or plant-specific aging management activities, the 

11 reviewer reviews the program element criteria for the AMP or activities against the criteria 

12 defined in the SRP-SLR, Appendix A.1, “Branch Technical Position, Aging Management 

13 Review—Generic,” Sections A.1.2.3.1 through A.1.2.3.10. 

14 If a sampling based inspection program (a type of condition monitoring program) is proposed as 

15 the basis for aging management, the reviewer ensures that the AMP actually performs 

16 inspections of the component(s) or structure(s) in the evaluation and that the applicant has 

17 appropriately justified that the inspection bases are capable of managing cumulative fatigue 

18 damage or cracking by fatigue or cyclical loading in the component(s) or structure(s), such that 

19 the TLAA may be accepted in accordance with 10 CFR 54.21(c)(1)(iii). 

20 4.6.3.2 Final Safety Analysis Report Supplement 

21 The reviewer verifies that the applicant has provided information, to be included in the FSAR 

22 supplement, that includes a summary description of the fatigue parameter TLAA evaluations for 

23 the containment liner plates, metal containments, and penetrations. SRP-SLR Table 4.6-1 

24 contains examples of acceptable FSAR Supplement information for this TLAA. The reviewer 

25 verifies that the applicant has provided an FSAR Supplement with information equivalent to that 

26 in Table 4.6-1. 

27 The NRC staff expects to impose a license condition on any renewed license to require the 

28 applicant to update its FSAR to include this FSAR supplement at the next update required 

29 pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 

30 complete, the applicant may make changes to the programs described in its FSAR supplement 

31 without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

32 the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final 

33 FSAR supplement before the license is renewed, no condition will be necessary. 

34 As noted in Table 4.6-1, the applicant need not incorporate the implementation schedule into its 

35 FSAR. However, the review should verify that the applicant has identified and committed in the 

36 SLRA to any future aging management activities, including enhancements and commitments to 

37 be completed before the subsequent period of extended operation. The NRC staff expects to 

38 impose a license condition on any renewed license to ensure that the applicant will complete 

39 these activities no later than the committed date. 

40 4.6.4 Evaluation Findings 

41 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

42 provisions of this section and to support the following conclusions, depending on the applicant’s 

43 choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be included in the Safety Evaluation Report. 
4.6-7 

1 On the basis of its review, as discussed above, the NRC staff concludes that 

2 the applicant has provided an acceptable demonstration, pursuant to 

3 10 CFR 54.21(c)(1), that the [the reviewer inserts the type of fatigue parameter 

4 evaluation] TLAA evaluations, [choose which is appropriate] (i) remains valid for 

5 the subsequent period of extended operation, (ii) has been projected to the end 

6 of the subsequent period of extended operation, or (iii) the effects of aging on the 

7 intended function(s) will be adequately managed during the subsequent period of 

8 extended operation. The NRC staff also concludes that the FSAR supplement 

9 contains an appropriate summary description of the [the reviewer inserts the type 

10 of fatigue parameter evaluation] TLAA evaluations for the subsequent period of 

11 extended operation as reflected in the license condition. 

12 4.6.5 Implementation 

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

14 method described herein will be used by the NRC staff in its evaluation of conformance with 

15 NRC regulations. 

16 4.6.6 References

17 1. NRC. NUREG-0661, “Mark I Containment Long-Term Program Resolution of Generic 

18 Technical Activity A-7.” Washington, DC: U.S. Nuclear Regulatory Commission. 

19 July 1980. 

20 2. American Society of Mechanical Engineers, Boiler and Pressure Vessel (B&PV) Code, 

21 Section III, Division 2, “Code for Concrete Containments, Rules for Construction of 

22 Nuclear Facility Components,” New York City, New York (as endorsed in Regulatory 

23 Guide 1.136, “Design Limits, Loading Combinations, Materials, Construction, and 

24 Testing of Concrete Containments.”). 

25 3. American Society of Mechanical Engineers, Boiler and Pressure Vessel (B&PV) Code, 

26 Section III, Division 1, “Subsection NE, Class MC Components, Rules for Construction of 

27 Nuclear Facility Components,” New York City, New York. 

28 4. American Society of Mechanical Engineers, Boiler and Pressure Vessel (B&PV) Code, 

29 Section III, Division 1, “Subsection NC, Class 2 Components, Rules for Construction of 

30 Nuclear Facility Components,” New York City, New York. 

31 5. Electric Power Research Institute (EPRI) TR-1003456, “Aging Management Guideline 

32 for Commercial Nuclear Power Plants Electrical and Mechanical Penetrations,” 

33 Palo Alto, California, April 2002.
4.6-8 

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

Containments, and Penetrations Fatigue TLAA Evaluation 

10 CFR 54.21(c)(1)(i) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

Current fatigue parameter evaluations remain valid 

during the subsequent period of extended operation. 

Completed 

10 CFR 54.21(c)(1)(ii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

Fatigue parameter evaluations have been reevaluated 

based on revised numbers of occurrences and severities 

of cyclic loads projected for the subsequent period of 

extended operation. The revised fatigue parameter 

values remain within allowable limits for the subsequent 

period of extended operation. 

Completed 

10 CFR 54.21(c)(1)(iii) Example 

TLAA Description of Evaluation 

Implementation 

Schedule* 

Containment 

Liner Plates, 

Metal 

Containments, 

and 

Penetrations 

Fatigue 

The containment liner plates, metal containments, and 

penetrations provide an essentially leak-tight barrier. 

The applicant identifies an aging management program 

(AMP) to manage the effects of fatigue on such 

components during the subsequent period of extended 

operation. The program monitors and tracks the number 

of cycles and occurrences and severities of relevant 

transients. The program is effective when fatigue 

evaluations and/or fatigue usage remain within the 

allowable limits or requires corrective actions 

(e.g., reanalyses and/or component replacement) when 

the limits are exceeded. If the component is replaced, 

the fatigue parameter value for the replacement should 

be shown to be less than the allowable limit during the 

subsequent period of extended operation. 

Proposed TLAA 

AMP should be 

implemented 

before the 

subsequent period 

of extended 

operation. 

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

that the applicant has identified and committed in the subsequent license renewal application to any future aging 

management activities to be completed before the subsequent period of extended operation. The NRC staff expects 

to impose a license condition on any subsequent renewed license to ensure that the applicant will complete these 

activities no later than the committed date. 

Note: All containment components need not meet the same requirement. It is likely that the liner plate and the 

bellows may be evaluated per 10CFR54.21(c)(1)(i), while high energy penetrations may be evaluated per 

10CFR54.21(c)(1)(ii). 
4.7-1 

1 4.7 Other Plant-Specific Time-Limited Aging Analyses 

2 Review Responsibilities 

3 Primary—Office of Nuclear Reactor Regulation (NRR) branch responsible for the time-limited 

4 aging analysis (TLAA) issues 

5 Secondary—Other branches responsible for systems, as appropriate 

6 4.7.1 Areas of Review 

7 There are certain plant-specific safety analyses that may involve time-limited assumptions 

8 defined by the current operating term of the plant (for example, aspects of the reactor vessel 

9 design) and may, therefore, be TLAAs. Pursuant to Title 10 of the Code of Federal Regulations

10 (10 CFR) 54.21(c), a subsequent license renewal (SLR) applicant is required to evaluate 

11 TLAAs. The definition of TLAAs is provided in 10 CFR 54.3 and in Section 4.1 of this Standard 

12 Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants 

13 (SRP-SLR). 

14 As indicated in 10 CFR 54.30, the adequacy of the plant’s current licensing basis (CLB) is not 

15 an area within the scope of the SLR review. Any questions regarding the adequacy of the CLB 

16 must be addressed under the backfit rule (10 CFR 50.109) and are separate from the license 

17 renewal process. SLR reviews focus on the subsequent period of extended operation. 

18 Pursuant to 10 CFR 54.30, if the reviews required by 10 CFR 54.21(a) or (c) show that there is 

19 not reasonable assurance during the current license term that licensed activities will be 

20 conducted in accordance with the CLB, the licensee is required to take measures under its 

21 current license to ensure that the intended functions of those systems, structures, and 

22 components (SSCs) are maintained in accordance with the CLB throughout the term of the 

23 current license. The adequacy of the measures for the term of the current license is not within 

24 the scope of the SLR review. 

25 Pursuant to 10 CFR 54.21(c), an applicant must provide a listing of TLAAs and plant-specific 

26 exemptions that are based on TLAAs. The U.S. Nuclear Regulatory Commission (NRC) staff 

27 reviews the applicant’s identification of TLAAs and exemptions separately, following the 

28 guidance in Section 4.1 of this SRP-SLR. 

29 The NRC staff has developed review procedures for the evaluation of certain TLAAs. If an 

30 applicant identifies these TLAAs as applicable to its plant, the NRC staff reviews them 

31 separately, following the guidance in Sections 4.2 through 4.6 of this SRP-SLR. 

32 Table 4.7-1 provides examples of potential plant-specific TLAA topics. The reviewer follows the 

33 generic guidance in this section of the SRP-SLR for reviewing these and any other plant-specific 

34 TLAAs that have been identified by the applicant. For particular systems, the reviewers 

35 from branches responsible for those systems may be requested to assist in the review, 

36 as appropriate. 
4.7-2 

1 The following sub-sections identify the areas of review for plant-specific TLAAs. 

2 4.7.1.1 Time-Limited Aging Analysis 

3 The applicant’s evaluation of the TLAA for the subsequent period of extended operation 

4 is reviewed. 

5 4.7.1.2 Final Safety Analysis Report Supplement 

6 The FSAR supplement summarizing the applicant’s evaluation of the TLAA for the subsequent 

7 period of extended operation is reviewed. 

8 4.7.2 Acceptance Criteria 

9 The acceptance criteria for the areas of review described in Section 4.7.1 delineate acceptable 

10 methods for meeting the requirements of 10 CFR 54.21(c)(1) and 10 CFR 54.21(d). 

11 4.7.2.1 Time-Limited Aging Analysis 

12 Pursuant to 10 CFR 54.21(c)(1), an applicant must demonstrate one of the following for TLAAs: 

13 (i) The analyses remain valid for the period of extended operation; 

14 (ii) The analyses have been projected to the end of the period of extended 

15 operation; or 

16 (iii) The effects of aging on the intended function(s) will be adequately managed for 

17 the period of extended operation. 

18 Acceptance criteria for each TLAA demonstration are discussed in the following subsections. 

19 4.7.2.1.1 10 CFR 54.21(c)(1)(i) 

20 The applicant must demonstrate that the analysis remains valid for the subsequent period of 

21 extended operation. The analysis remains valid because it is shown to be bounding even 

22 during the subsequent period of extended operation. No changes to the existing analysis 

23 are necessary. 

24 4.7.2.1.2 10 CFR 54.21(c)(1)(ii) 

25 The applicant must demonstrate that the analysis has been projected to the end of the 

26 subsequent period of extended operation. The existing analysis is updated or recalculated to 

27 show acceptable results for the subsequent period of extended operation. 

28 4.7.2.1.3 10 CFR 54.21(c)(1)(iii) 

29 The applicant must demonstrate that the effects of aging on the intended function(s) will be 

30 adequately managed for the subsequent period of extended operation. Appendix A.1 of this 

31 SRP-SLR provides the acceptance criteria for programs and activities used to manage the 

32 effects of aging. 
4.7-3 

1 4.7.2.2 Final Safety Analysis Report Supplement 

2 The summary description of the applicant’s TLAA evaluation should be sufficiently 

3 comprehensive such that later changes can be controlled by 10 CFR 50.59. The summary 

4 description should identify which demonstration from 10 CFR 54.21(c)(1) was chosen and 

5 provide the results of the evaluation used to make that demonstration. 

6 4.7.3 Review Procedures 

7 For certain applicants, plant-specific analyses may meet the definition of a TLAA as given in 

8 10 CFR 54.3. The concern for SLR is that these analyses may not have properly considered 

9 the full length of the subsequent period of extended operation, which may change conclusions 

10 with regard to safety and the capability of SSCs within the scope of the Rule to perform or one 

11 or more safety functions. The review of these TLAAs provides assurance that the effects of 

12 aging are properly addressed through the subsequent period of extended operation.

13 The following sub-sections provide the review procedures for each area of review described in 

14 Section 4.7.1. 

15 4.7.3.1 Time-Limited Aging Analysis 

16 For each TLAA, the review procedures depend on the applicant’s choice of methods of 

17 compliance in 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

18 4.7.3.1.1 10 CFR 54.21(c)(1)(i) 

19 Justification provided by the applicant is reviewed to verify that the existing analysis remains 

20 valid for the subsequent period of extended operation. The existing analysis should be shown 

21 to be bounding even during the subsequent period of extended operation. 

22 The applicant describes the TLAA with respect to the objectives of the analysis, assumptions 

23 used in the analysis, conditions, acceptance criteria, relevant aging effects, and intended 

24 function(s). For those analyses that consider cyclic loading, each load or transient type should 

25 be identified along with the corresponding number of total cycles assumed in the analysis and 

26 the number of cycles that are anticipated to occur through the subsequent period of extended 

27 operation. The applicant shows that (a) conditions and assumptions used in the analysis 

28 already address the relevant aging effects for the subsequent period of extended operation, and 

29 (b) acceptance criteria are maintained to provide reasonable assurance that the intended 

30 function(s) is maintained. Thus, no reanalysis is necessary. 

31 In some instances, the applicant may identify activities to be performed to verify the assumption 

32 basis for the calculation (e.g., cycle counting). An evaluation of that activity is provided by the 

33 applicant. The reviewer assures that the applicant’s verification activities are sufficient to 

34 confirm the validity of the calculation assumptions for the subsequent period of 

35 extended operation. 

36 If the TLAA must be modified or recalculated to extend the period of evaluation to consider the 

37 subsequent period of extended operation, then reevaluation should be addressed under 

38 10 CFR 54.21(c)(1)(ii). 
4.7-4 

1 4.7.3.1.2 10 CFR 54.21(c)(1)(ii) 

2 The documented results of the revised analyses are reviewed to verify that their period of 

3 evaluation is extended such that they are valid for the subsequent period of extended operation. 

4 The applicable analysis technique can be the one that is in effect in the plant’s CLB at the time 

5 that the subsequent license renewal application (SLRA) is filed. 

6 The applicant may recalculate the TLAA using an 80-year period to show that the acceptance 

7 criteria continue to be satisfied for the subsequent period of extended operation. The applicant 

8 also may revise the TLAA by recognizing and reevaluating any overly conservative conditions 

9 and assumptions. Examples include relaxing overly conservative assumptions in the original 

10 analysis, using new or refined analytical techniques, and performing the analysis using an 

11 80-year period. The applicant should provide a sufficient description of the analysis and 

12 document the results of the reanalysis to show that it is satisfactory for the subsequent period of 

13 extended operation. 

14 As applicable, the plant’s code of record is used for the reevaluation, or the applicant may 

15 update to a later code edition pursuant to 10 CFR 50.55a. In the latter case, the reviewer 

16 verifies that the requirements in 10 CFR 50.55a are met. 

17 In some cases, the applicant may identify activities to be performed to verify the assumption 

18 basis for the calculation (e.g., cycle counting). An evaluation of that activity is provided by 

19 the applicant. The reviewer assures that the applicant’s verification activities are sufficient 

20 to confirm the validity of the calculation assumptions for the subsequent period of extended 

21 operation. 

22 4.7.3.1.3 10 CFR 54.21(c)(1)(iii) 

23 Under this option, the applicant proposes to manage the aging effects associated with the TLAA 

24 by an aging management program (AMP) or aging management activities in the same manner 

25 as described in the integrated plant assessment (IPA) in 10 CFR 54.21(a)(3). The reviewer 

26 reviews the applicant’s AMP or aging management activities to verify that the effects of aging on 

27 the intended function(s) are adequately managed consistent with the CLB for the subsequent 

28 period of extended operation. 

29 The applicant identifies the structures and components (SCs) associated with the TLAA. The 

30 TLAA is described with respect to the objectives of the analysis, conditions, assumptions used, 

31 acceptance criteria, relevant aging effects, and intended function(s). The reviewer uses the 

32 guidance in Section A.1 of this SRP-SLR to ensure that the effects of aging on the SC-intended 

33 function(s) are adequately managed for the subsequent period of extended operation. 

34 4.7.3.2 Final Safety Analysis Report Supplement 

35 The reviewer verifies that the applicant has provided information to be included in the Final 

36 Safety Analysis Report (FSAR) supplement that includes a summary description of the 

37 evaluation of each TLAA. Each such summary description is reviewed to verify that it is 

38 sufficiently comprehensive. 

39 The NRC staff expects to impose a condition on any subsequently renewed license to require 

40 the applicant to update its FSAR to include this FSAR supplement at the next update required 

41 pursuant to 10 CFR 50.71(e)(4). As part of the license condition, until the FSAR update is 
4.7-5 

1 complete, the applicant may make changes to the programs described in its FSAR supplement 

2 without prior NRC approval, provided that the applicant evaluates each such change pursuant to 

3 the criteria set forth in 10 CFR 50.59. If the applicant updates the FSAR to include the final 

4 FSAR supplement before the license is renewed, then no such condition is necessary. 

5 The applicant need not incorporate the implementation schedule into its FSAR. However, the 

6 reviewer should verify that the applicant has identified and committed in the SLRA to any future 

7 aging management activities, including enhancements and commitments to be completed 

8 before the subsequent period of extended operation. The NRC staff expects to impose a 

9 condition on any subsequently renewed license to require the applicant to complete these 

10 activities no later than the committed date. 

11 4.7.4 Evaluation Findings 

12 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

13 provisions of Section 4.7 and whether the NRC staff’s evaluation supports conclusions of the 

14 following type, depending on the applicant’s choice of 10 CFR 54.21(c)(1)(i), (ii), or (iii), to be 

15 included in the Safety Evaluation Report: 

16 On the basis of its review, as discussed above, the NRC staff concludes that 

17 the applicant has provided an acceptable demonstration, pursuant to 

18 10 CFR 54.21(c)(1), that, for the (name of specific) TLAA, [choose which 

19 is appropriate] 

20 (i) The analyses remain valid for the subsequent period of extended operation, 

21 (ii) The analyses have been projected to the end of the period of extended 

22 operation, or 

23 (iii) The effects of aging on the intended function(s) will be adequately managed for 

24 the subsequent period of extended operation. The NRC staff also concludes that 

25 the FSAR supplement contains an appropriate summary description of this TLAA 

26 evaluation for the period of extended operation, as required by 10 CFR 54.21(d). 

27 4.7.5 Implementation 

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

29 method described herein is used by the NRC staff in its evaluation of conformance with 

30 NRC regulations. 

31 4.7.6 References 

32 None
4.7-6 

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

BWRs 

Re-flood thermal shock of the reactor pressure vessel 

Re-flood thermal shock of the core shroud and other reactor vessel internals 

Loss of preload for core plate rim hold-down bolts 

Erosion of the main steam line flow restrictors 

Susceptibility to irradiation-assisted stress corrosion cracking 

PWRs 

Reactor pressure vessel underclad cracking 

Leak-before-break 

Reactor coolant pump flywheel fatigue crack growth 

Response to NRC Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification” 

Response to NRC Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor 

Cooling Systems” 

BWRs and PWRs 

Fatigue of cranes (crane cycle limits) 

Fatigue of the spent fuel pool liner 

Corrosion allowance calculations 

Flaw growth due to stress corrosion cracking 

Predicted lower limit 

Grouted tendon prestress systems, structures, and components 
5-1 

1 5 TECHNICAL SPECIFICATIONS CHANGES 

2 5.1 Review of Technical Specifications Changes and Additions 

3 Necessary to Manage the Effects of Aging During the Subsequent 

4 Period of Extended Operation 

5 Review Responsibilities 

6 Primary— Division of License Renewal (DLR) technical branch for reviewing applicable 

7 technical specifications (TS) requirements for relevance to specific aging management 

8 programs (AMPs) or time-limited aging analyses (TLAAs) 

9 Secondary—DLR projects branch responsible for processing of the subsequent license 

10 renewal application (SLRA); supporting branches in Office of Nuclear Reactor Regulation, 

11 Division of Engineering (NRR/DE); Office of Nuclear Reactor Regulation, Division of Inspection 

12 and Regional Support (NRR/DIRS); Office of Nuclear Reactor Regulation, Division of Policy and 

13 Rulemaking (NRR/DPR); Office of Nuclear Reactor Regulation, Division of Operating Reactor 

14 Licensing (NRR/DORL) or Office of Nuclear Reactor Regulation, Division of Safety Systems 

15 (NRR/DSS) 

16 5.1.1 Areas of Review 

17 The requirements in Title 10 of the Code of Federal Regulations (10 CFR) 54.22 (Ref. 2) require 

18 an applicant to identify any new TSs or TS changes (i.e., amendments) that are needed to 

19 manage the effects of aging during the period of extended operations. This section of the 

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

21 Power Plants (SRP-SLR) provides guidance for determining whether plant TS changes need to 

22 be included in a plant-specific SLRA. 

23 5.1.2 Acceptance Criteria 

24 The TS for a relicensed light-water reactor facility may contain specific TS sections that may 

25 have relationships to AMPs or TLAAs that are identified in an SLRA. The following provide 

26 examples of (but are not limited to) TS requirements that may relate to AMPs or TLAAs: 

27  For TS that include administrative controls section provisions that establish preventative 

28 maintenance and periodic visual inspection requirements for plant systems located 

29 outside of containment [i.e., for applicant’s whose SLRAs include periodic surveillance 

30 and preventative maintenance AMPs and whose current licensing basis (CLBs) include 

31 these types of TS requirements], the AMPs should establish the relationship of the TS 

32 requirements to the applicable program element criteria for their AMPs, as applicable. 

33  For TS that include administrative controls section provisions that establish fuel oil 

34 testing requirements for emergency diesel fuel storage tanks (i.e., for applicant’s whose 

35 SLRAs include diesel fuel oil testing AMPs and with CLBs that include these types of TS 

36 requirements), the AMPs should establish the relationship of the TS requirements to the 

37 applicable program element criteria for their AMPs, as applicable. 

38  For TS that include pressure-temperature (P-T) limits for their reactor vessels and 

39 reactor coolant pressure boundary components in the limiting conditions of operations 

40 (LCOs) and control updates of these P-T limits through their 10 CFR 50.90 license 
5-2 

1 amendment request process, the TS requirements may have direct bearing on how the 

2 P-T limit TLAAs for the SLRA are accepted in accordance with 10 CFR 54.21(c)(1)(i), 

3 (ii), or (iii). 

4  For TS that include P-T limits for their reactor vessels and reactor coolant pressure 

5 boundary components in a pressure-temperature limit report (PTLR) and controls 

6 updates of the P-T limits and PTLR in accordance with a program and process 

7 controlled by the administrative controls section of their TS, the TS requirements may 

8 have direct bearing on how the P-T limit TLAAs for the SLRA are accepted in 

9 accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii). 

10 Acceptance criteria for plant-specific TS are contained in the specific TS provisions or 

11 alternatively in referenced documents invoked by the TS requirements. For those 

12 SLRAs for plants whose CLBs include TS requirements that relate to an AMP’s program 

13 element bases for managing specific aging effects, the TS requirements should be 

14 reviewed to confirm that they remain adequate for managing the aging effects that are 

15 within the scope of the AMPs. Otherwise, the TS requirements should be amended 

16 accordingly as part of the SLRA in accordance with 10 CFR 54.22 and the changes in 

17 the TS requirement criteria factored into the program element bases for the AMP, 

18 as appropriate. 

19 For those TS requirements that relate to TLAAs, the TS requirements and any 

20 methodologies or processes invoked by the TS requirements should be reviewed to see 

21 if they need to be amended or new TS requirements need to be proposed in order to 

22 demonstrate adequate compliance of the TLAAs in accordance with 10 CFR 

23 54.21(c)(1)(i), (ii), or (iii). Otherwise, TS changes that are determined as being 

24 necessary to disposition TLAAs in accordance with the requirements of 

25 10 CFR 54.21(c)(1)(i), (ii), or (iii) should be included in the SLRA as part of TS change 

26 requests under 10 CFR 54.22. This may include TS changes that may be needed for 

27 P-T limit TLAAs controlled by PTLR processes, if it is determined that the current P-T 

28 limit methodologies approved and invoked by the current administrative controls TS 

29 requirements cannot generate P-T limits for the subsequent license renewal (SLR) 

30 period that will comply with the P-T limit requirements in 10 CFR Part 50, Appendix G 

31 (Ref. 1), and Appendix G of the ASME Code Section XI edition of record for the facility. 

32 5.1.3 Review Procedures 

33 The reviewer should review the applicant’s operating license, including the TS that are included 

34 as part of the operating license, and procedures to ensure that the applicant has identified all 

35 appropriate TS changes or additions that may impact AMPs or TLAAs during the subsequent 

36 period of extended operation. If it is determined that new TS requirements, or new operating 

37 license conditions are needed to manage specific aging effects, or that changes to the existing 

38 TS requirements need to be amended in order to manage such aging effects, the reviewer 

39 determines that those license amendments are submitted with the SLRA for U.S. Nuclear 

40 Regulatory Commission (NRC) approval in accordance with the requirement in 10 CFR 54.22. 

41 Examples of existing TS requirements that may be used to manage the effects of aging include 

42 but are not limited to: (a) preventative maintenance and periodic visual inspection requirements 

43 for plant systems located outside of containment, (b) diesel fuel oil monitoring requirements or 

44 surveillance requirements that are listed in the administrative controls sections of the TS, which 

45 may form the bases for fuel oil chemistry programs used to manage loss of material due to 
5-3 

1 general, pitting, crevice, and microbiologically-induced corrosion in emergency diesel fuel oil 

2 system components, and (c) requirements in the TS that govern the applicant’s updates to the 

3 P-T limits of their plants that constitute part of the mandatory bases for managing and analyzing 

4 loss of fracture toughness due to neutron irradiation embrittlement in ferritic steel components of 

5 the reactor vessel and reactor coolant pressure boundary. This latter example is a TLAA. 

6 5.1.4 Evaluation Findings

7 The reviewer determines whether the applicant has provided sufficient information to satisfy the 

8 provisions of this section, and whether the NRC staff’s evaluation supports one of the following 

9 three conclusions listed below that is to be included in the NRC staff’s safety evaluation report, 

10 as applicable for the review of the SLRA: 

11 On the basis of its review, as discussed above, the NRC staff concludes that the 

12 applicant has provided an acceptable basis for concluding that the SLRA does 

13 not need to include any new TS requirements or TS amendments to manage the 

14 effects of aging during the SLR period. 

15 On the basis of its review, as discussed above, the NRC staff concludes that the 

16 applicant has provided a list of all new TS provisions or TS changes in the SLRA 

17 that are needed to manage the effects of aging during the SLR period, as 

18 required by 10 CFR 54.22. The NRC staff also concludes that these TS changes 

19 will be capable of managing the effects of aging in accordance the requirement in 

20 10 CFR 54.21(a)(3). 

21 Pursuant to the requirement in 10 CFR 54.22, as discussed above, the NRC staff 

22 concludes that the applicant has provided those new TS provisions or TS 

23 changes in the SLRA needed to manage [INSERT APPLICABLE AGING 

24 EFFECT], as evaluated in [INSERT NAME of TLAA] for the SLR period. The 

25 NRC staff also concludes that these TS changes adequately demonstrate that 

26 the [INSERT NAME of TLAA and then INSERT one of the Following Statements 

27 to finish off this conclusion] . . .will remain valid for the SLR period, as required by 

28 10 CFR 54.21(c)(1)(i),” has been adequately projected to the end of the SLR 

29 period, as required by 10 CFR 54.21(c)(1)(ii),” effects of [INSERT APPLICABLE 

30 AGING EFFECT AND MECHANISM] on the intended functions of the [INSERT 

31 APPLICABLE STRUCTURES OR COMPONENTS EVALUATED IN THE TLAA] 

32 during the SLR period, as required by 10 CFR 54.21(c)(1)(iii). 

33 5.1.5 Implementation 

34 The method described herein is used by the NRC staff to evaluate compliance with NRC 

35 regulation in 10 CFR 54.22, which requires the applicant to identify any new TS 

36 requirements or TS amendments that are necessary to manage the effects of aging during 

37 an SLR period. 

38 5.1.6 References 

39 1. 10 CFR Part 50, “Fracture Toughness Requirements.” Appendix G. Washington, DC: 

40 U.S. Nuclear Regulatory Commission. 2015. 
5-4 

1 2. 10 CFR 54.22, “Contents of Application–Technical Specifications.” Washington, DC: 

2 U.S. Nuclear Regulatory Commission. 2015.
1 APPENDIX A 

2 GENERAL NRC STAFF POSITIONS AND GUIDANCE

A.1-1 

1 APPENDIX A—GENERAL NRC STAFF POSITIONS AND GUIDANCE 

2 A.1 Aging Management Review—Generic 

3 (Branch Technical Position RLSB-1) 

4 A.1.1 Background 

5 Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(3), a license renewal 

6 application (LRA) is required to demonstrate that the effects of aging on structures and 

7 components (SCs) subject to an aging management review (AMR) are adequately managed so 

8 their intended functions will be maintained consistent with the current licensing basis (CLB) for 

9 the subsequent period of extended operation. The purpose of this Branch Technical Position 

10 (BTP) (RLSB-1) is to address the aging management demonstration that has not been 

11 addressed specifically in Chapters 3 and 4 of this Standard Review Plan for Review of 

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

13 The subsequent license renewal (SLR) process is not intended to demonstrate absolute 

14 assurance that SCs will not fail, but rather that there is reasonable assurance that they will 

15 perform such that the intended functions are maintained consistent with the CLB during the 

16 subsequent period of extended operation. 

17 There are generally four types of aging management programs (AMPs): (i) prevention, 

18 (ii) mitigation, (iii) condition monitoring, and (iv) performance monitoring. 

19 Prevention Programs preclude the effects of aging. For example, coating programs prevent 

20 external corrosion of a tank. 

21 Mitigation Programs attempt to slow the effects of aging. For example, water chemistry 

22 programs mitigate internal corrosion of piping. 

23 Condition Monitoring Programs inspect for the presence and extent of aging effects or perform 

24 tests that monitor potential changes in a components or structure’s material condition. 

25 Examples of programs that involve inspections are the visual examination of concrete structures 

26 for cracking and the ultrasonic examination of pipe wall for flow-accelerated corrosion 

27 (FAC)-induced wall thinning. Examples of programs that involve material testing are reactor 

28 pressure vessel material surveillance capsule testing programs that monitor for embrittlement in 

29 ferritic reactor pressure vessel component’s and material testing programs that monitor for 

30 degradation in spent fuel pool neutron absorption materials. 

31 Performance Monitoring Programs test the ability of a structure or component to perform its 

32 intended function(s). For example, the ability of the tubes on heat exchangers to transfer heat 

33 is tested. 

34 More than one type of AMP may be implemented to ensure that aging effects are managed. 

35 For example, in managing internal corrosion of piping, a mitigation program (water chemistry) 

36 may be used to minimize susceptibility to corrosion. However, it may also be necessary to have 

37 a condition monitoring program (ultrasonic inspection) to verify that corrosion is indeed 

38 insignificant. In addition, some AMPs may incorporate more than one of the activities of 

39 prevention, mitigation, condition monitoring, or performance monitoring. For example, open 

40 cycle cooling water programs may incorporate combinations of inspection (condition monitoring) 

41 and flow testing (performance monitoring) activities. 
A.1-2 

1 A.1.2 Branch Technical Position 

2 A.1.2.1 Applicable Aging Effects 

3 1. The determination of applicable aging effects is based on degradation mechanisms that 

4 have occurred and those that potentially could cause SC degradation. The materials, 

5 environment, stresses, service conditions, operating experience, and other relevant 

6 information should be considered in identifying applicable aging effects. The effects of 

7 aging on the intended function(s) of SCs also should be considered. 

8 2. Relevant aging information may be contained in, but is not limited to, the following 

9 documents: (i) plant-specific maintenance and inspection records; (ii) plant-specific site 

10 deviation or issue reports; (iii) plant-specific U.S. Nuclear Regulatory Commission (NRC) 

11 and Institute of Nuclear Power Operations (INPO) inspection reports; (iv) plant-specific 

12 licensee self-assessment reports; (v) plant-specific and other licensee event report 

13 (LERs); (vi) NRC, INPO, and vendor generic communications; and (vii) generic safety 

14 issues (GSIs)/unresolved safety issues (USIs); NUREG reports; and Electric Power 

15 Research Institute (EPRI) reports. 

16 3. If operating experience or other information indicates that a certain aging effect may be 

17 applicable and an applicant determines that it is not applicable to its specific plant, the 

18 reviewer may question the absence of this aging effect if the applicant has not provided 

19 a sufficient basis in its subsequent license renewal application (SLRA). For example, 

20 the question could cite a previous application review, NRC generic communications, 

21 engineering judgment, relevant research information, or other industry experience as the 

22 basis for the question. Simply citing that the aging effect is listed in the Generic Aging 

23 Lessons Learned for Subsequent License Renewal (GALL-SLR) Report is not a 

24 sufficient basis. For example, it may be that the aging effect is applicable to a 

25 pressurized water reactor (PWR) component, but the applicant’s plant is a boiling water 

26 reactor (BWR) and does not have such a component. In this example, using the 

27 GALL-SLR Report merely as a checklist is not appropriate. 

28 4. An aging effect may not have been identified in the GALL-SLR Report, if it arises out of 

29 industry experience after the issuance of the GALL-SLR Report. The reviewer should 

30 ensure that the applicant has evaluated the latest industry experience to identify all 

31 applicable aging effects. 

32 5. An aging effect should be identified as applicable for SLR even if there is a prevention or 

33 mitigation program associated with that aging effect. For example, water chemistry, a 

34 coating, or use of cathodic protection could prevent or mitigate corrosion, but corrosion 

35 should be identified as applicable for SLR, and the AMR should consider the adequacy 

36 of the AMP referencing water chemistry, coating, or cathodic protection. 

37 6. Specific identification of aging mechanisms is not a requirement; however, it is an option 

38 to identify specific aging mechanisms and the associated aging effects in the integrated 

39 plant assessment (IPA). 

40 7. The applicable aging effects to be considered for SLR include those that could result 

41 from normal plant operation, including plant or system operating transients and plant 

42 shutdown. Specific aging effects from abnormal events need not be postulated for SLR. 

43 However, if an abnormal event has occurred at a particular plant, its contribution to the 
A.1-3 

1 aging effects on SCs for SLR should be considered for that plant. For example, if a resin 

2 intrusion has occurred in the reactor coolant system at a particular plant, the contribution 

3 of this resin intrusion event to aging should be considered for that plant. 

4 Design basis events (DBEs) are abnormal events; they include design basis pipe break, loss of 

5 coolant accident (LOCA), and safe shutdown earthquake (SSE). Potential aging effects 

6 resulting from DBEs are addressed, as appropriate, as part of the plant’s CLB. There are other 

7 abnormal events which should be considered on a case-by-case basis. For example, abuse 

8 due to human activity is an abnormal event; aging effects from such abuse need not be 

9 postulated for SLR. When a safety-significant piece of equipment is accidentally damaged by a 

10 licensee, the licensee is required to take immediate corrective action under existing procedures 

11 (see 10 CFR Part 50 Appendix B) to ensure functionality of the equipment. The equipment 

12 degradation is not due to aging; corrective action is not necessary solely for the subsequent 

13 period of extended operation. However, leakage from bolted connections should not be 

14 considered as abnormal events. Although bolted connections are not supposed to leak, 

15 experience shows that leaks do occur, and the leakage could cause corrosion. In addition, 

16 condensation frequently occurs during humid periods of normal plant operation and can also 

17 occur during plant shutdown when normally hot components might be below the dew point. The 

18 aging effects from leakage of bolted connections and condensation occurring during humid 

19 periods of normal plant operations should be evaluated for SLR. Condensation during plant 

20 shutdowns could result in aging effects such as reduced thermal insulation resistance due to 

21 moisture intrusion and should be evaluated for SLR. It is less likely that condensation during 

22 plant shutdowns would result in loss of material, unless plant-specific operating experience 

23 dictates otherwise (e.g., as a result of extended plant shutdowns). 

24 An aging effect due to an abnormal event does not preclude that aging effect from occurring 

25 during normal operation for the subsequent period of extended operation. For example, a 

26 certain PWR licensee observed clad cracking in its pressurizer, and attributed that to an 

27 abnormal dry out of the pressurizer. Although dry out of a pressurizer is an abnormal event, the 

28 potential for clad cracking in the pressurizer during normal operation should be evaluated for 

29 SLR. This is because the pressurizer is subject to extensive thermal fluctuations and water 

30 level changes during plant operation, which may result in clad cracking given sufficient 

31 operating time. The abnormal dry out of the pressurizer at that certain plant may have merely 

32 accelerated the rate of the aging effect. 

33 A.1.2.2 Aging Management Program for Subsequent License Renewal 

34 1. An acceptable AMP should consist of the 10 elements described in Table A.1-1, as 

35 appropriate. These program elements are discussed further in Position A.1.2.3 below. 

36 2. All programs and activities that are credited for managing a certain aging effect for a 

37 specific structure or component should be described. These programs and activities 

38 may be evaluated together for the 10 elements described in Table A.1-1, as appropriate. 

39 3. The risk significance of a structure or component could be considered in evaluating the 

40 robustness of an AMP. Probabilistic arguments may be used to develop an approach for 

41 aging management adequacy. However, use of probabilistic arguments alone is not an 

42 acceptable basis for concluding that, for those SCs subject to an AMR, the effects of 

43 aging will be adequately managed in the subsequent period of extended operation. 

44 Thus, risk significance may be considered in developing the details of an AMP for the 
A.1-4 

1 structure or component for SLR, but may not be used to conclude that no AMP is 

2 necessary for SLR. 

3 4. For programs that rely on NRC-endorsed technical or topical reports (TRs), the scope of 

4 the AMP includes the applicant’s bases for resolving or addressing any NRC limitations 

5 or applicant/licensee action items that are placed on the activities for implementing a 

6 given report’s methodology. These limitations or action items are identified in the NRC’s 

7 safety evaluation on the TR’s methodology and recommended activities. If it is 

8 determined that the response to a specific applicant action item will result in the need for 

9 augmentation of specific programmatic criteria beyond those activities recommended in 

10 the applicable TR, the applicant should define the AMP accordingly to identify the AMP 

11 program element or elements that are impacted by the basis for responding to the 

12 applicable action item and the adjustments that will need to be made to the TR guidance 

13 recommendations, as defined in the impacted program elements for the AMP and 

14 applicable to the CLB and design basis for the facility. It is also recommended that the 

15 applicants provide their bases for resolving the specific limitations or action items in 

16 Appendix C of their SLRAs. 

17 A.1.2.3 Aging Management Program Elements 

18 A.1.2.3.1 Scope of Program 

19 The specific program necessary for SLR should be identified. The scope of the program should 

20 include the specific SCs, the aging of which the program manages. 

21 A.1.2.3.2 Preventive Actions 

22 1. The activities for prevention and mitigation programs should be described. These 

23 actions should mitigate or prevent aging degradation. 

24 2. Some condition or performance monitoring programs do not rely on preventive actions 

25 and thus, this information need not be provided. 

26 3. In some cases, condition or performance monitoring programs may also rely on 

27 preventive actions. The specific prevention activities should be specified. 

28 A.1.2.3.3 Parameters Monitored or Inspected 

29 1. This program element should identify the aging effects that the program manages and 

30 should provide a link between the parameter or parameters that will be monitored and 

31 how the monitoring of these parameters will ensure adequate aging management. 

32 2. For a condition monitoring program, the parameter monitored or inspected should be 

33 capable of detecting the presence and extent of aging effects. Some examples are 

34 measurements of wall thickness and detection and sizing of cracks. 

35 3. For a performance monitoring program, a link should be established between the 

36 degradation of the particular structure or component-intended function(s) and the 

37 parameter(s) being monitored. An example of linking the degradation of a passive 

38 component-intended function with the performance being monitored is linking the fouling 

39 of heat exchanger tubes with the heat transfer-intended function as identified by a 
A.1-5 

1 change in the differential temperature across the heat exchanger tubes. This could be 

2 monitored by periodic heat balances. Since this example deals only with one intended 

3 function of the tubes (heat transfer), additional programs may be necessary to manage 

4 other intended function(s) of the tubes, such as pressure boundary. Thus, a 

5 performance monitoring program must ensure that the SCs are capable of performing 

6 their intended functions by using a combination of performance monitoring and 

7 evaluation (if outside acceptable limits of acceptance criteria) that demonstrate that 

8 a change in performance characteristic is a result of an age-related 

9 degradation mechanism. 

10 4. For prevention or mitigation programs, the parameters monitored should be the specific 

11 parameters being controlled to achieve prevention or mitigation of aging effects. An 

12 example is the coolant oxygen level that is being controlled in a water chemistry program 

13 to mitigate pipe cracking. 

14 A.1.2.3.4 Detection of Aging Effects 

15 1. Detection of aging effects should occur before there is a loss of the SC-intended 

16 function(s). The parameters to be monitored or inspected should be appropriate to 

17 ensure that the SC-intended function(s) will be adequately maintained for SLR under all 

18 CLB design conditions. Thus, the discussion for the “detection of aging effects” program 

19 element should address (a) how the program element would be capable of detecting or 

20 identifying the occurrence of age-related degradation or an aging effect prior to a loss of 

21 SC-intended function or (b) for preventive/mitigative programs, how the program would 

22 be capable of preventing or mitigating their occurrence prior to a loss of a SC-intended 

23 function. The discussion should provide information that links the parameters to be 

24 monitored or inspected to the aging effects being managed. 

25 2. Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth 

26 principles. A degraded or failed component reduces the reliability of the system, 

27 challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a 

28 structure or component should be managed to ensure its availability to perform its 

29 intended function(s) as designed when called upon. In this way, all system 

30 level-intended function(s), including redundancy, diversity, and defense-in-depth 

31 consistent with the plant’s CLB, would be maintained for SLR. A program based solely 

32 on detecting structure and component failure should not be considered as an effective 

33 AMP for SLR. 

34 3. This program element describes “when,” “where,” and “how” program data are collected 

35 (i.e., all aspects of activities to collect data as part of the program). 

36 4. For condition monitoring programs, the method or technique (such as visual, volumetric, 

37 or surface inspection), frequency, and timing of new, one-time inspections may be linked 

38 to plant-specific or industry-wide operating experience. The discussion provides 

39 justification, including codes and standards referenced, that the technique and frequency 

40 are adequate to detect the aging effects before a loss of SC-intended function. A 

41 program based solely on detecting SC failures is not considered an effective AMP. 

42 For a condition monitoring program, when sampling is used to represent a larger 

43 population of SCs, applicants provide the basis for the inspection population and sample 

44 size. The inspection population should be based on such aspects of the SCs as a 
A.1-6 

1 similarity of materials of construction, fabrication, procurement, design, installation, 

2 operating environment, or aging effects. The sample size should be based on such 

3 aspects of the SCs as the specific aging effect, location, existing technical information, 

4 system and structure design, materials of construction, service environment, or previous 

5 failure history. The samples are biased toward locations most susceptible to the specific 

6 aging effect of concern in the subsequent period of extended operation. Provisions on 

7 expanding the sample size when degradation is detected in the initial sample should 

8 also be included. For multiunit sites, samples are conducted at all units. Provisions for 

9 expanding the sample size when degradation is detected in the initial sample 

10 are included. 

11 5. For a performance monitoring program, the “detection of aging effects” program element 

12 should discuss and establish the monitoring methods that will be used for performance 

13 monitoring. In addition, the “detection of aging effects” program element should also 

14 establish and justify the frequency that will be used to implement these performance 

15 monitoring activities. 

16 6. For a prevention or mitigation program, the “detection of aging effects” program element 

17 should discuss and establish the monitoring methods that the program will use to 

18 monitor for the preventive or mitigative parameters that the program controls and should 

19 justify the frequency of performing these monitoring activities. 

20 A.1.2.3.5 Monitoring and Trending 

21 1. Monitoring and trending activities should be described, and they should provide a 

22 prediction of the extent of degradation and thus effect timely corrective or mitigative 

23 actions. Plant-specific and/or industrywide operating experience may be considered in 

24 evaluating the appropriateness of the technique and frequency. 

25 2. This program element describes “how” the data collected are evaluated and may also 

26 include trending for a forward look. This includes an evaluation of the results against the 

27 acceptance criteria and a prediction regarding the rate of degradation in order to confirm 

28 that timing of the next scheduled inspection will occur before a loss of SC-intended 

29 function. Although aging indicators may be quantitative or qualitative, aging indicators 

30 should be quantified, to the extent possible, to allow trending. The parameter or 

31 indicator trended should be described. The methodology for analyzing the inspection or 

32 test results against the acceptance criteria should be described. Trending is a 

33 comparison of the current monitoring results with previous monitoring results in order to 

34 make predictions for the future. 

35 A.1.2.3.6 Acceptance Criteria 

36 1. The quantitative or qualitative acceptance criteria of the program and its basis should be 

37 described. The acceptance criteria, against which the need for corrective actions are 

38 evaluated, should ensure that the SC-intended function(s) are maintained consistent 

39 with all CLB design conditions during the subsequent period of extended operation. The 

40 program should include a methodology for analyzing the results against applicable 

41 acceptance criteria. 

42 For example, carbon steel pipe wall thinning may occur under certain conditions due to 

43 FAC. An AMP for FAC may consist of periodically measuring the pipe wall thickness 
A.1-7 

1 and comparing that to a specific minimum wall acceptance criterion. Corrective action is 

2 taken, such as piping replacement, before deadweight, seismic, and other loads, and 

3 this acceptance criterion must be appropriate to ensure that the thinned piping would be 

4 able to carry these CLB design loads. This acceptance criterion should provide for 

5 timely corrective action before loss of intended function under these CLB design loads. 

6 2. Acceptance criteria could be specific numerical values, or could consist of a discussion 

7 of the process for calculating specific numerical values of conditional acceptance criteria 

8 to ensure that the SC-intended function(s) will be maintained under all CLB design 

9 conditions. Information from available references may be cited. 

10 3. It is not necessary to justify any acceptance criteria taken directly from the design basis 

11 information that is included in the Final Safety Analysis Report (FSAR), plant Technical 

12 Specifications (TS), or other codes and standards incorporated by reference into NRC 

13 regulations; they are a part of the CLB. Nor is it necessary to justify the acceptance 

14 criteria that have been established in either NRC-accepted or NRC-endorsed 

15 methodology, such as those that may be given in NRC-approved or NRC-endorsed 

16 topical reports or NRC-endorsed codes and standards; the acceptance criteria 

17 referenced in these types of documents have been subject to an NRC review process 

18 and have been approved or endorsed for their application to an NRC-approved or 

19 NRC-endorsed evaluation methodology. Also, it is not necessary to discuss CLB design 

20 loads if the acceptance criteria do not permit degradation because a SC without 

21 degradation should continue to function as originally designed. Acceptance criteria, 

22 which do permit degradation, are based on maintaining the intended function under all 

23 CLB design loads. 

24 A.1.2.3.7 Corrective Actions 

25 1. Actions to be taken when the acceptance criteria are not met should be described in 

26 appropriate detail or referenced to source documents. Corrective actions, including root 

27 cause determination and prevention of recurrence, should be timely. 

28 2. If corrective actions permit analysis without repair or replacement, the analysis should 

29 ensure that the SC-intended function(s) are maintained consistent with the CLB. 

30 3. Results that do not meet the acceptance criteria are addressed as conditions adverse to 

31 quality or significant conditions adverse to quality under those specific portions of the 

32 quality assurance (QA) program that are used to meet Criterion XVI, “Corrective Action,” 

33 of 10 CFR Part 50, Appendix B. Appendix A.2 describes how an applicant may apply its 

34 10 CFR Part 50, Appendix B, QA program to fulfill the corrective actions element of this 

35 AMP for both safety-related and nonsafety-related SCs within the scope of this program. 

36 4. For plant‐specific programs that rely on NRC‐endorsed Technical or TRs, the corrective 

37 actions are implemented in accordance with corrective actions recommended in the 

38 applicable TR or TRs, or the applicant’s 10 CFR Part 50, Appendix B, QA process, 

39 as applicable. 

40 A.1.2.3.8 Confirmation Process 

41 1. The confirmation process should be described. The process ensures that appropriate 

42 corrective actions have been completed and are effective. 
A.1-8 

1 2. The confirmation process is addressed through those specific portions of the QA 

2 program that are used to meet Criterion XVI, “Corrective Action,” of 10 CFR Part 50, 

3 Appendix B. Appendix A.2 describes how an applicant may apply its 10 CFR Part 50, 

4 Appendix B, QA program to fulfill the confirmation process element of this AMP for both 

5 safety-related and nonsafety-related systems, structures, and components (SSCs) within 

6 the scope of this program. 

7 3. When significant conditions adverse to quality are identified, there should be follow-up 

8 activities to confirm that the corrective actions have been completed, a root cause 

9 determination was performed, and recurrence will be prevented. 

10 4. For plant‐specific condition monitoring programs that rely on the augmented inspection 

11 and evaluation methodologies in NRC‐endorsed Technical or TRs, the administrative 

12 controls for these types of programs, including their implementing procedures and 

13 review and approval processes, are implemented in accordance existing site 10 CFR 50 

14 Appendix B, QA Programs, or their equivalent, as applicable. Additional administrative 

15 controls criteria may apply as identified in the TRs or in other industry reports or 

16 guidelines, such as those developed by (but not limited to) Nuclear Energy Institute 

17 (NEI), the EPRI Boiling Water Reactor Vessel and Internals Project (BWRVIP), EPRI 

18 Materials Reliability Program (MRP), BWR Owners Group, PWR Owners Group, or 

19 industry vendors, such as AREVA, Westinghouse, or General Electric (GE) or 

20 GE-Hitachi. 

21 A.1.2.3.9 Administrative Controls 

22 1. The administrative controls of the program should be described. Administrative controls 

23 provide a formal review and approval process. 

24 2. Administrative controls are addressed through the QA program that is used to meet the 

25 requirements of 10 CFR Part 50, Appendix B, associated with managing the effects of 

26 aging (e.g., document control, special processes, and test control). Appendix A.2 

27 describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to 

28 fulfill the administrative controls element of this AMP for both safety-related and 

29 nonsafety-related SCs within the scope of this program. 

30 3. For plant‐specific condition monitoring programs that rely on the augmented inspection 

31 and evaluation methodologies in NRC‐endorsed Technical or TRs, the administrative 

32 controls for these types of programs, including their implementing procedures and 

33 review and approval processes, are implemented in accordance existing site 10 CFR 50 

34 Appendix B, QA Programs, or their equivalent, as applicable. Additional administrative 

35 controls criteria may apply as identified in the TRs or in other industry reports or 

36 guidelines, such as those developed by (but not limited to) NEI, the EPRI BWRVIP, 

37 EPRI MRP, BWR Owners Group, PWR Owners Group, or industry vendors, such as 

38 AREVA, Westinghouse, or GE or GE-Hitachi. 

39 A.1.2.3.10 Operating Experience 

40 1. Consideration of future plant-specific and industry operating experience relating to AMPs 

41 should be discussed (See Appendix A.4). Reviews of operating experience by the 

42 applicant in the future may identify areas where AMPs should be enhanced or new 

43 programs developed. An applicant should commit to a future review of plant-specific 
A.1-9 

1 and industry operating experience to confirm the effectiveness of its AMPs or indicate a 

2 need to develop new AMPs. This information should provide objective evidence to 

3 support the conclusion that the effects of aging will be managed adequately so that the 

4 SC intended function(s) will be maintained during the subsequent period of extended 

5 operation. 

6 2. Currently available operating experience with existing programs should be discussed. 

7 The discussion should note any changes to the programs during the first period of 

8 extended operation. The operating experience of existing programs, including past 

9 corrective actions resulting in program enhancements or additional programs, should be 

10 considered. A past failure would not necessarily invalidate an AMP because the 

11 feedback from operating experience should have resulted in appropriate program 

12 enhancements or new programs. This information can show where an existing program 

13 has succeeded and where it has not been fully effective in intercepting aging 

14 degradation in a timely manner. This information should provide objective evidence to 

15 support the conclusion that the effects of aging will be managed adequately so that the 

16 SC-intended function(s) will be maintained during the subsequent period of extended 

17 operation. 

18 3. Currently available operating experience applicable to new programs should also be 

19 discussed. For new AMPs that have yet to be implemented at an applicant’s facility, the 

20 programs have not yet generated any operating experience. However, there may be 

21 other relevant plant-specific or generic industry operating experience that is relevant to 

22 the program elements, even though the operating experience was not identified through 

23 implementation of the new program. Thus, when developing the elements for new 

24 programs, an applicant should consider the impact of relevant operating experience from 

25 implementation of its existing AMPs and from generic industry operating experience. 

26 4. For plant‐specific condition monitoring programs that rely on the augmented inspection 

27 and evaluation methodologies in NRC‐endorsed Technical or TRs, the administrative 

28 controls for these types of programs, including their implementing procedures and 

29 review and approval processes, are implemented in accordance with existing site 

30 10 CFR 50 Appendix B, QA Programs, or their equivalent, as applicable. Additional 

31 administrative controls criteria may apply as identified in the TRs or in other industry 

32 reports or guidelines, such as those developed by (but not limited to) NEI, the EPRI 

33 BWRVIP, EPRI MRP, BWR Owners Group, PWR Owners Group, or industry vendors, 

34 such as AREVA, Westinghouse, or GE or GE-Hitachi. 

35 A.1.3 References 

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

37 License Renewal Rule,” Nuclear Energy Institute, Revision 6
A.1-10 

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

License Renewal 

Element Description 

1. Scope of Program Scope of program includes the specific SCs subject to an 

AMR for SLR. 

2. Preventive Actions Preventive actions should prevent or mitigate 

aging degradation. 

3. Parameters Monitored or 

Inspected 

Parameters monitored or inspected should be linked to the 

degradation of the particular SC-intended function(s). 

4. Detection of Aging Effects Detection of aging effects should occur before there is a loss 

of SC-intended function(s). This includes aspects such as 

method or technique (i.e., visual, volumetric, surface 

inspection), frequency, sample size, data collection, and 

timing of new/one-time inspections to ensure timely detection 

of aging effects. 

5. Monitoring and Trending Monitoring and trending should provide predictability of the 

extent of degradation, and timely corrective or 

mitigative actions. 

6. Acceptance Criteria Acceptance criteria, against which the need for corrective 

action will be evaluated, should ensure that the SC-intended 

function(s) are maintained under all CLB design conditions 

during the subsequent period of extended operation. 

7. Corrective Actions Corrective actions, including root cause determination and 

prevention of recurrence, should be timely. 

8. Confirmation Process Confirmation process should ensure that corrective actions 

have been completed and are effective. 

9. Administrative Controls Administrative controls should provide a formal review and 

approval process. 

10. Operating Experience Operating experience applicable to the AMP, including past 

corrective actions resulting in program enhancements or 

additional programs, should provide objective evidence to 

support the conclusion that the effects of aging will be 

managed adequately so that the SC-intended function(s) will 

be maintained during the subsequent period of extended 

operation. Operating experience with existing programs 

should be discussed 

In addition, the ongoing review of both plant-specific and 

industry operating experience ensures that the AMP is 

effective in managing the aging effects for which it is credited. 

The AMP is either enhanced or new AMPs are developed, as 

appropriate, when it is determined through the evaluation of 

operating experience that the effects of aging may not be 

adequately managed.
A.2-1 

1 A.2 Quality Assurance for Aging Management Programs 

2 (Branch Technical Position IQMB-1) 

3 A.2.1 Background 

4 The subsequent license renewal application (SLRA) is required to demonstrate that the effects 

5 of aging on structures and components (SCs) subject to an aging management review (AMR) 

6 will be managed adequately to ensure that their intended functions are maintained consistent 

7 with the current licensing basis (CLB) of the facility for the subsequent period of extended 

8 operation. Therefore, those aspects of the AMR process that affect quality of safety-related 

9 systems, structures, and components (SSCs) are subject to the quality assurance (QA) 

10 requirements of Title 10 of the Code of Federal Regulations (10 CFR) Part 50 Appendix B. For 

11 nonsafety-related SCs subject to an AMR, the existing 10 CFR Part 50 Appendix B QA program 

12 may be used by the applicant to address the elements of corrective actions, the confirmation 

13 process, and administrative controls, as described in Branch Technical Position RLSB-1 

14 (Appendix A.1 of this SRP-SLR). The confirmation process ensures that appropriate corrective 

15 actions have been completed and are effective. Administrative controls should provide for a 

16 formal review and approval process. Generic Aging Lessons Learned for Subsequent License 

17 Renewal (GALL-SLR) Report describes how a subsequent license renewal (SLR) applicant can 

18 rely on the existing requirements in 10 CFR Part 50 Appendix B, “Quality Assurance Criteria for 

19 Nuclear Power Plants and Fuel Reprocessing Plants,” to satisfy these program 

20 elements/attributes. The purpose of this branch technical position (IQMB-1) is to describe an 

21 acceptable process for implementing the corrective actions, the confirmation process, and 

22 administrative controls of aging management programs (AMPs) for SLR. 

23 A.2.2 Branch Technical Position 

24 1. Safety-related SCs are subject to 10 CFR Part 50 Appendix B requirements, which are 

25 adequate to address all quality-related aspects of an AMP consistent with the CLB of the 

26 facility for subsequent period of extended operation. 

27 2. For nonsafety-related SCs that are subject to an AMR for SLR, an applicant has the 

28 option to expand the scope of its 10 CFR Part 50 Appendix B program to include these 

29 SCs and to address corrective actions, the confirmation process, and administrative 

30 controls for aging management during the subsequent period of extended operation. 

31 The reviewer verifies that the applicant has documented such a commitment in the Final 

32 Safety Analysis Report (FSAR) supplement in accordance with 10 CFR 54.21(d). 

33 3. If an applicant chooses an alternative means to address corrective actions, the 

34 confirmation process, and administrative controls for managing aging of nonsafety35 related SCs that are subject to an AMR for SLR, the applicant’s proposal is reviewed on 

36 a case-by-case basis following the guidance in Branch Technical Position RLSB-1 

37 (Appendix A.1 of this SRP-SLR). 

38 A.2.3 References 

39 None. 

A.3-1 

1 A.3 Generic Safety Issues Related to Aging (Branch Technical Position 

2 RLSB-2) 

3 A.3.1 Background 

4 Unresolved safety issues (USIs) and generic safety issues (GSIs) are identified and tracked in 

5 the U.S. Nuclear Regulatory Commission (NRC) formal resolution process set forth in 

6 NUREG–0933, “Resolution of Generic Safety Issues,” which is updated periodically (Ref. 1). 

7 Appendix B to NUREG–0933 contains a listing of those issues that are applicable to operating 

8 and future plant. NUREG–0933 is a source of information on generic concerns identified by the 

9 NRC. Some of these concerns may be related to the effects of aging or time-limited aging 

10 analyses (TLAAs) for systems, structures, or components within the scope of the subsequent 

11 license renewal (SLR) review. The purpose of this Branch Technical Position (RLSB-2) is to 

12 address the SLR treatment of an aging effect or a TLAA which is a subject of an USI or a GSI 

13 [60 Federal Register (FR) 22484]. 

14 A.3.2 Branch Technical Position 

15 A.3.2.1 Treatment of GSIs 

16 The license renewal rule requires that aging effects be managed to ensure that the structures 

17 and components (SC) intended function(s) are maintained and that TLAAs are evaluated for 

18 SLR. Thus, all applicable aging effects of SCs subject to an aging management review (AMR) 

19 and all TLAAs must be evaluated, regardless of whether they are associated with GSIs or USIs. 

20 The agency’s Generic Issues Program process for resolving GSIs is described in Management 

21 Directive 6.4, “Generic Issues Program,” dated November 17, 2009, and SECY-07-0022, 

22 “Status Report on Proposed Improvements to the Generic Issues Program.” 

A.4-1 

1 A.4 Operating Experience for Aging Management Programs 

2 A.4.1 Background 

3 Operating experience is a crucial element of an effective aging management program (AMP). It 

4 provides the basis to support all other elements of the AMP and, as a continuous feedback 

5 mechanism, drives changes to these elements to ensure the overall effectiveness of the AMP. 

6 Operating experience should provide objective evidence to support the conclusion that the 

7 effects of aging are managed adequately so that the structures and components (SC)-intended 

8 function(s) will be maintained during the subsequent period of extended operation. Under their 

9 current operating licenses, subsequent license renewal (SLR) applicants are required to 

10 implement programs for the ongoing review of operating experience, such as those established 

11 in accordance with Item I.C.5, “Procedures for Feedback of Operating Experience to Plant 

12 Staff,” of NUREG–0737, “Clarification of TMI Action Plan Requirements” (Ref. 3). 

13 A.4.2 Position 

14 The systematic review of plant-specific and industry operating experience concerning aging 

15 management and age-related degradation ensures that the SLR AMPs are, and will continue to 

16 be, effective in managing the aging effects for which they are credited. The AMPs should either 

17 be enhanced or new AMPs developed, as appropriate, when it is determined through the 

18 evaluation of operating experience that the effects of aging may not be adequately managed. 

19 AMPs should be informed by the review of operating experience on an ongoing basis, 

20 regardless of the AMP’s implementation schedule. 

21 Acceptable Use of Existing Programs 

22 Programs and procedures relied upon to meet the requirements of Title 10 of the Code of 

23 Federal Regulations (10 CFR) Part 50, Appendix B (Ref. 1) and NUREG–0737 (Ref. 3), 

24 Item I.C.5, may be used for the capture, processing, and evaluation of operating experience 

25 concerning age-related degradation and aging management during the term of a renewed 

26 operating license. As part of meeting the requirements of NUREG–0737, Item I.C.5, the 

27 applicant should actively participate in the Institute of Nuclear Power Operations’ operating 

28 experience program [formerly the Significant Event Evaluation and Information Network (SEEIN) 

29 program endorsed in U.S. Nuclear Regulatory Commission (NRC) Generic Letter (GL) 82-04, 

30 “Use of INPO SEEIN Program”] (Ref. 2). These programs and procedures may also be used for 

31 the translation of recommendations from the operating experience evaluations into plant actions 

32 (e.g., enhancement of AMPs and development of new AMPs). While these programs and 

33 procedures establish a majority of the functions necessary for the ongoing review of operating 

34 experience, they are also subject to further review as discussed below. 

35 Areas of Further Review 

36 To ensure that the programmatic activities for the ongoing review of operating experience are 

37 adequate for SLR, the following points should be addressed: 

38  The programs and procedures relied upon to meet the requirements of 10 CFR Part 50, 

39 Appendix B, and NUREG–0737, Item I.C.5, explicitly apply to and otherwise would not 

40 preclude the consideration of operating experience on age-related degradation and 

41 aging management. Such operating experience can constitute information on the SCs 

42 identified in the integrated plant assessment; their materials, environments, aging 
A.4-2 

1 effects, and aging mechanisms; the AMPs credited for managing the effects of aging; 

2 and the activities, criteria, and evaluations integral to the elements of the AMPs. To 

3 satisfy this criterion, the applicant should use the option described in A.2.2.2 of Standard 

4 Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power 

5 Plants (SRP-SLR) Appendix A.2, “Quality Assurance for Aging Management Programs 

6 (Branch Technical Position IQMB-1),” to expand the scope of its 10 CFR Part 50, 

7 Appendix B, program to include nonsafety-related SCs. 

8  The license renewal interim staff guidance (LR-ISG) documents and revisions to the 

9 Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report 

10 should be considered as sources of industry operating experience and evaluated 

11 accordingly. There should be a process to identify such documents and process them 

12 as operating experience. 

13  All incoming plant-specific and industry operating experience should be screened to 

14 determine whether it may involve age-related degradation or impacts to aging 

15 management activities. 

16  A means should be established within the corrective action program to identify, track, 

17 and trend operating experience that specifically involves age-related degradation. There 

18 should also be a process to identify adverse trends and to enter them into the corrective 

19 action program for evaluation. 

20  Operating experience items identified as potentially involving aging should receive 

21 further evaluation. This evaluation should specifically take into account the following: 

22 (a) systems, structures, and components (SSCs), (b) materials, (c) environments, 

23 (d) aging effects, (e) aging mechanisms, (f) AMPs, and (g) the activities, criteria, and 

24 evaluations integral to the elements of the AMPs. The assessment of this information 

25 should be recorded with the operating experience evaluation. If it is found through 

26 evaluation that any effects of aging may not be adequately managed, then a corrective 

27 action should be entered into the 10 CFR Part 50, Appendix B, program to either 

28 enhance the AMPs or develop and implement new AMPs. 

29  Assessments should be conducted on the effectiveness of the AMPs and activities. 

30 These assessments should be conducted on a periodic basis that is not to exceed once 

31 every five years. They should be conducted regardless of whether the acceptance 

32 criteria of the particular AMPs have been met. The assessments should also include 

33 evaluation of the AMP or activity against the latest NRC and industry guidance 

34 documents and standards that are relevant to the particular program or activity. If there 

35 is an indication that the effects of aging are not being adequately managed, then a 

36 corrective action is entered into the 10 CFR Part 50, Appendix B, program to either 

37 enhance the AMPs or develop and implement new AMPs, as appropriate. 

38  Training on age-related degradation and aging management should be provided to those 

39 personnel responsible for implementing the AMPs and those personnel who may submit, 

40 screen, assign, evaluate, or otherwise process plant-specific and industry operating 

41 experience. The scope of training should be linked to the responsibilities for processing 

42 operating experience. This training should occur on a periodic basis and include 

43 provisions to accommodate the turnover of plant personnel. 
A.4-3 

1  Guidelines should be established for reporting plant-specific operating experience on 

2 age-related degradation and aging management to the industry. This reporting should 

3 be accomplished through participation in the Institute of Nuclear Power Operations’ 

4 operating experience program. 

5  Any enhancements necessary to fulfill the above criteria should be put in place no later 

6 than the date the renewed operating license is issued and implemented on an ongoing 

7 basis throughout the term of the renewed license. 

8 The programmatic activities for the ongoing review of plant-specific and industry experience 

9 concerning age-related degradation and aging management should be described in the 

10 subsequent license renewal application (SLRA), including the Final Safety Analysis Report 

11 (FSAR) supplement. Alternate approaches for the future consideration of operating experience 

12 are subject to NRC review on a case-by-case basis. 

13 A.4.3 References 

14 1. 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and 

15 Fuel Reprocessing Plants, Office of the Federal Register, National Archives and 

16 Records Administration, 2015. 

17 2. Generic Letter 82-04, “Use of INPO SEE-IN Program.” March 9, 1982. U.S. Nuclear 

18 Regulatory Commission. 

19 3. NUREG–0737, “Clarification of TMI Action Plan Requirements,” U.S. Nuclear Regulatory 

20 Commission. 

21 4. NUREG–1801, “Generic Aging Lessons Learned (GALL) Report,” U.S. Nuclear 

22 Regulatory Commission.







NUREG

-2192

Draft

Standard Review Plan for Review of Subsequent License Renewal 

Applications for Nuclear Power Plants